bluuebunny/crossref_metadata_2025_split huggingface dataset:
Brunei Shell Petroleum Champion Field Gas-lift Optimization Project – FieldWare Production Universe Implementation in a Brown Field
Authors: Wee Thierry , Turco Agostino , McIlroy Roger , de Boer Frank , Cramer Ronald , Dolan Michael J. 
Published: June 2014

Abstract
Brunei Shell Petroleum (BSP) is undergoing a significant modernization of its gas-lift system in the Champion field in Brunei. With smart gas-lift flow control valves, BSP is continuously controlling the gas for gas lifted wells on remote, unmanned production facilities. Shell Global Solutions is assisting this process by the implementation of the FieldWare* Real-time Optimization (RTO) system. This system, which uses data driven models to optimize production, has already proven its value in this field during a prior pilot installation. The successful implementation of BSP Champion field gas-lift optimization is an example of the significant value that Smart Fields* implementation brings to a brown field. As a result Gas-lift efficiency has been sustainably increased by 40% in one of the implemented platforms. This paper discusses the RTO project execution, technology involved, the implementation process, its results and finally the business benefits achieved.
New Technique for Addressing SIMOPS Challenges During Installation of New Offshore Platform
Authors: Ataya Zaher M. 
Published: June 2014

Abstract
SIMOPS stands for simultaneous or concurrent operations, which present serious potential HSE and operational risks as it, combine the hazards and risks of drilling and production or production and construction or drilling and construction and or drilling, production and construction (TRIOPS). Shutting down any operation for conducting the other one(s), may not be easy, feasible and or cost efficient decision. The current paper focuses on a new technique and method for addressing SIMOPS risks and challenges, especially during the installation of new offshore gas injection platform in close position to the existing super complex (production station), and sub sea pipe lines. The study sets good practices and standards that can be used by other offshore oil and gas companies to reduce SIMOPS risks to as low as reasonably practicable (ALARP) level.
Effect of Formation Stress Distribution on Hydraulic Fracture Reorientation in Tight Gas Sands
Authors: Aghighi M. A. , Rahman S. S. , Rahman M. M. 
Published: June 2014

Abstract
Initial period of production from a fracture stimulated tight gas sands can alter stress distribution around the hydraulic fracture. This allows a new fracture to reorient along a different azimuth, even up to 90 degrees, thereby providing access to less depleted zones and retrieving productivity. Success of hydraulic fracture re-stimulation significantly depends on the stress state of the wellbore adjacent area. Using a finite element based fully coupled poroelastic numerical model which includes wellbore, poroelastic formation, a pair of finite conductive fracture and refracture, this paper examines the effect of production induced stress perturbation on the initiation and orientation of a secondary fracture in hydraulically fractured tight gas reservoirs. Results of this study have shown that the area of stress reorientation around a producing hydraulically fractured well is constrained by two distinct planes. By simulating wellbore re-pressurization, it has been also shown that such stress distribution, which is induced by initial production period, can lead to further propagation of the primary hydraulic fracture instead of reorientation of hydraulic fracture. Furthermore, it has been also observed that properly oriented perforation prior to refracture treatment and/or existence of micro-fractures at the wellbore wall can facilitate refracture reorientation before the primary hydraulic fracture starts propagating.
Revamping Old Fields Using I-Field Technologies
Authors: Al-Khamis Mohammed N. , Al-Hamzani Housam J. , Al-Adel Mahdi F. 
Published: June 2014

Abstract
With the ever growing demand for energy in the world, the need for timely and accurate data from oil fields to allow proper decision making becomes very crucial. Recent evolution in oil field technologies has made a great revolution in the oil and gas industry all over the world, leading to the emerging development of intelligent fields (I-Fields)1–4. The integration of I-Field technologies, whether downhole or at surface, coupled with communication networks along with sophisticated simulation and monitoring applications has led to significant advancements not only in monitoring and control capabilities, but rather also in decision making processes5. Therefore, the overall system upgrade has resulted in an enhancement of the field surveillance, which will lead to higher levels of oil production in these assets as a consequence of Saudi Aramco's development strategy for these fields.
Three previously produced oil fields that were mothballed were revitalized and redeveloped after extensive drilling and workover programs. The latest downhole production technologies were installed in all oil production and water injection wells. Furthermore the project called for the construction of new oil and gas processing and water injection facilities, all linked to their respective wells via an elaborate fiber optic communication network for optimum control and surveillance capabilities in real time mode. The production and injection strategies were further optimized making use of I-Field components, such as Permanent Downhole Monitoring Systems (PDHMS), Smart Well Completion Systems, Multiphase Flow Meters (MPFM), Single Phase Flow Meters, pressure and temperature sensors with specially tailored monitoring, and simulation software.
This paper will describe how the installed and applied I-Field technologies in these three fields have allowed better data management, helped in optimizing the production and injection and overall has enhanced the operation and safety of the field operations. Moreover, several examples will be discussed showing the benefits of real-time surveillance in optimizing the fields’ performance with a special focus on the use of monitoring and simulation tools to more accurately mimic the current performance of the wells, and consequently used to generate optimized production and injection scenarios.
Improving Allocation and Hydrocarbon Accounting Accuracy Using New Techniques
Authors: Cramer Ron , Schotanus Dave , Ibrahim Kolin , Colbeck Nick 
Published: June 2014

Summary
In the oil industry, it is necessary to reconcile fiscally measured hydrocarbon production with estimated production from associated wells. This process is known as "allocation" and is important for a number of reasons, including accounting for field production to owners/governments, field surveillance, and volumetric input to reservoir simulators.
Traditionally, allocation is performed on a monthly basis, reconciling the "less-accurate" sum of the well tests adjusted by well uptimes with the "more-accurate" fiscal measurements. This process is subject to a number of inherent inaccuracies, including less-than-perfect well tests, lack of knowledge of precisely when the wells were interrupted, unknown well-flow changes, and uncertainty as to how to allocate effectively the difference between fiscal and well-test measurements.
Ineffective allocation can lead to financial consequences caused by inaccuracies in volumes allocated between various owners and tax regimes. Inaccuracies can also feed through to reservoir simulators, which may be used in corresponding decision-making processes (e.g., where to drill the next well). These inaccuracies are generally compounded with time because allocation is performed month after month throughout the field life cycle.
Associated with hydrocarbon accounting are key performance indicators (KPIs) (e.g., well daily production and deferment rates).
The purpose of this paper is to describe Shell's experiences in improving allocation accuracy and automatic KPI reporting through more-effective use of available production data and by using a continuous, rather than a discontinuous, hydrocarbon accounting process.
Nimr Water Treatment Project - Up Scaling A Reed Bed Trail To Industrial
Authors: Breuer Roman , Al-Asmi Said Rashid 
Published: June 2014

Abstract
The Nimr Water Treatment Project is to develop and set up an effective water treatment plant for the residual waters produced from the Petroleum Development Oman (PDO) oil wells in its Nimr Oil Field with a capacity to process a minimum of 45,000 m³/day produced water.
PDO initially established a pilot project 10 years ago in the Nimr Oilfied in the Sultanate of Oman; see Figure 1 Map of Omani Oilfields – The Nimr Cluster. The technology used was based on a constructed wetland followed by an evaporation pond to remove the produced water contaminants and reduce the effluent. Using the experience of the pilot a Design, Build, Own, Operate and Transfer (DBOOT) tender process was started to upscale the pilot from a capacity of 1,000 m³/d to 45,000 m³/d in 2007. The project was awarded late in 2008 and based on PDO and the contractor's experience one of the biggest commercial constructed wetlands is build for water treatment.
Main technology changes were made based on pilot test results, an extended study of the water characteristics and climate data. The result is the construction of an approximately 600 ha large facility comprising of an Oil/Water Separator to recover remaining crude oil, a surface flow Constructed Wetland and finally an engineered salt works facility to include the option for salt recovery. Additionally, potential benefits of biomass utilisation and carbon credit values are investigated to be potentially included into the project after commissioning. Construction works have commenced in May 2009 and water is bound to flow in January 2011.
Reducing the Carbon Footprint of Drilling and Completion Operations
Authors: Gilbert Y. , Hagström M. , Getliff J. M. 
Published: June 2014

Abstract
The use of planning tools to minimize waste and discharges to the environment during well construction is fast becoming the norm in the oil and gas industry. Air emission control through the same approach is also desirable. Calculating the carbon footprint of a well construction operation is however usually done after the event. When planning the well, air emissions are generally taken into account through qualitative evaluations, and consideration of emissions from disposal activities appears to be somewhat rare. Nevertheless there is a clear advantage in a quantitative analysis of the operation, as it supports emission mitigation at source and allows the engineer to compare different operational choices.
The objective of the development work undertaken was to create a user-friendly yet scientifically defensible methodology for calculation of greenhouse gas (GHG) emissions, air pollutants, fuel consumption and fuel costs before well construction takes place. The aim was to enable engineers to compare different operational choices in a quantitative manner. The developed methodology utilises databases of equipment, specific energy consumption and specific emission factors and allows pre- operational calculations without the need for detailed data on actual power consumption or fuel use. This allows targeted emission mitigation to be incorporated into the planning stage.
The initial phase of the project included a review of GHG calculation methodologies and the air emission reporting requirements in the EU and the USA. Existing methodologies appear to have been designed to support post-operational calculations, where accurate data on fuel consumption and fuel consistency is known, thus some methodology development was required as such data is not available before an operation.
The approach used in this calculator takes into account all aspects of the operation that can be influenced by the operator: Logistics, equipment, fluid choices and waste management options, including different end disposal options. The results include both detailed breakdowns and rapid overviews of emission sources both for greenhouse gases and the traditional air pollutants. Applying the concepts developed in the planning stage supports identification of best practices and allows targeted improvement efforts towards areas of greater emissions. The actual tool can be used for both comparisons during the design stage and as an aid to audits for accurate post-operational emissions audits.
Production Processes Integration for Large Gas Basin – Burgos Asset
Authors: Sandoval G. , Martínez F. , Cadena A. , Bernal H. , Vega E. De , Navarro M. , García M. , Leal I. , Figón L. , Zambrano A. , Duran J. , García M. , Rangel M deL. , Garza E. , Corbellini F. , Mota M. , Escalona H. , Aguilar Y. , Corona A. , Oca A. Montes , Tortolero M. , Díaz T. , Álvarez N. , Montes E. , Romero E. , Suárez A. , Romay J. , Fuehrer F. , Kinani A. Al , Holy R. , Núñez G. , Vernus J. 
Published: June 2014

Abstract
This paper presents the advances in Production System Optimization for the largest gas field in Mexico. The Burgos Asset is a large gas brown field with reservoir characteristics like gas-loading backpressure, reduced permeability and tight gas formations where production declines rapidly. Due to the large number of wells (more than 3500 active wells) and the fact that 95% of the measured parameters are obtained by field operators, it is difficult to continuously monitor and to plan the usage of operational resources.
To help solve this situation, PEMEX and the service company (Schlumberger) implemented a production surveillance system that gathers all operational information providing storage, quality control, and developed engineering processes to estimate gas rates and liquid loading, monitors KPI and detects anomalies in operational events.
Implementation of this operational surveillance environment started in 2007, with a functionality that has been focused on monitoring KPI calculation and event analysis at well level. Due to the large number of wells and activities carried out by the Asset, the need arose to generate additional workflows that contribute to the production optimization process, candidate selection workflow for workover and artificial lift installation, allowing upscaling of the current solution to a level that supports the technical and economical decisions of the Asset.
As part of this requirement the team took the initiative to incorporate workflows of candidate recognition for workover, de-bottlenecking and optimization of a particular set of facilities, allowing the Asset to take corrective action in these areas and to plan the recommendations accordingly. Additionally, as proof of concept, an intelligent candidate selection system was implemented for artificial lift installation opportunities, using artificial intelligence tools such as data mining, improving decisions and results.
The initiatives mentioned above help to increase, validate and rank the Asset's diverse candidate basket and to integrate the economic constraints into the decision making process. The positive results that have been obtained in these focalized areas show a significant opportunity to be up scaled for the whole Asset.
ES-SAGD; Past, Present and Future
Authors: Orr Bryan 
Published: June 2014

Abstract
North America's long-term energy future depends heavily upon the Athabasca oilsands. Only 15% of these deposits are at mineable depths (&lt;90m) and thus 85% of the oilsands (232 billion bbl recoverable reserves) must be recovered using in-situ techniques. Steam Assisted Gravity Drainage (SAGD) has become the method of choice for oilsand producers and it is therefore critical to optimize this process.
ES-SAGD or expanding solvent steam assisted gravity drainage involves the co-injection of a hydrocarbon solvent and steam to improve recovery from the SAGD process. The hydrocarbon solvent is soluble in bitumen at reservoir conditions and serves to decrease its viscosity thereby increasing the production rate over a process driven solely by steam.
This paper investigates several ES-SAGD pilot projects with a focus on the Nexen-OPTI ES-SAGD project at Long Lake. Additionally, a literature search was performed and the data, found in public ES-SAGD papers on steam-solvent labs and simulation studies, is summarized. Nexen is also currently involved in a lab experiment being operated by AGAT involving a comparison of the performance of different hydrocarbon solvents for assisting the SAGD process.
ES-SAGD should be pursued because successful implementation would significantly improve profitability by accelerating production, decreasing water losses and decreasing steam requirements. Additionally this will address environmental concerns by decreasing CO2 emissions. ES-SAGD will also increase reserves both per well pair and on a total oilsands basis.
Application of Nanoparticle Saturated Injectant Gases for EOR of Heavy Oils
Authors: Shah Rusheet D. 
Published: June 2014

ABSTRACT
Heavy oil is an immense oil resource that is untapped because its highly viscous nature makes it difficult to produce. Currently, the heavy oil reservoir production challenges are addressed by thermal recovery techniques, CHOPS, chemical injection and miscible gas injection. In this work, the advantages of three different processes viz thermal, chemical and miscible gas injection have been merged together to come up with a novel viscosity reducing process for heavy oil. Metal Nanoparticles are used for thermal conductivity enhancement of super critical-CO2 (sc-CO2) or "Viscosity reducing Injectant" (VRI) for reducing the viscosity of heavy oil rapidly as compared to conventional sc-CO2 or VRI. A sc-CO2 soluble surfactant has also been added to the mixture to further enhance the viscosity reduction. Thus the thermal properties of metal nanoparticles, the chemical properties of surfactant and the miscible properties of sc-CO2 and VRI altogether reduce the viscosity of heavy oil.
Managed Pressure Drilling Avoids Losses while Improving Drilling and ECD Management in the Gulf of Thailand
Authors: Fredericks Paul , Garcia Greg , Sehsah Ossama 
Published: June 2014

Abstract
A number of oil fields in the Gulf of Thailand are characterized by severely depleted gas sands and unstable coal and shale. Operators drilling high angle and horizontal wells in those fields often have to contend with problems associated with high equivalent circulating density (ECD) and the narrow operating margin between fracture gradient and borehole stability.
Reaching total depth in those fields without losing returns is possible but it requires careful management of the ECD, vigilant hole cleaning practices, and controlled drilling. Unfortunately, success comes at the expense of drill time which is unavoidably reduced by those same conventional practices.
Automated Managed Pressure Drilling (MPD) was a solution used by one operator to improve drilling efficiency while still avoiding losses and maintaining wellbore stability. By taking advantage of the MPD system’s ability to manage the BHP when the mud pumps are off the operator was able to reduce the static mud weight below wellbore stability and the ECD below the fracture gradient. With the reduction in mud weight the operator was also able to change the mud rheology in other ways that contributed to improved hole cleaning.
Managed Pressure Drilling was initially used in a three well program in 2007 and later in an extended six well program in 2009. For most of the wells the drilling plan was the same: conventionally drill out of the 9–5/8” casing with an 8–1/2” bit down to the top of the depleted zones, lighten the mud density and rheology, bring the MPD system on line and drill through the depleted zone to the next casing point. However, midway through the second program the well plans changed and MPD was used to drill the entire 8–1/2” section.
For all nine wells, the MPD system remained the same: a dynamic pressure control system with an integrated real-time hydraulics model, an automated manifold and backpressure pump, and early kick detection equipment. Even though the trajectory changed from well to well, surface and downhole conditions remained relatively constant in terms of borehole and drill string geometry, stratigraphic sequence, mud rheology, drilling practices, MPD system, and rig type.
Such relatively constant conditions created favorable circumstances for the comparison of conventional and MPD practices. Results show that MPD enabled the operator to avoid losses and achieve noticeable improvements in drilling efficiency and ECD management. In addition, there were noticeable improvements in MPD performance in terms of transition times and BHP control.
Applications of Bio-enzymatic Completion Fluid in the Tight Sand Gas Reservoirs of Ordos Daniudi Gas Field
Authors: Qiang Lan , Gongrang Li , Jinghui Zhang , Haibin Li , Liping Wang 
Published: June 2014

Abstract
At present, Ordos Daniudi gas field is developed with the gas of Shan-1 and He-1 reservoirs, whose lithologies mainly are tight sands. The reservoirs have severely potential formation damages, induced by mechanisms such as strong water-sensitivity, water-blocking and solid slugging with small particles. The solid-free brine completion fluids are usually used in Daniudi gas field, but it had little positive effect on the formation damage relieving, sometimes even aggravated formation damage. This article has developed a new bio-enzymatic completion fluid. The laboratory test results showed that the completion fluid can thoroughly clean out the mud cakes, evenly relieve the pore slugging damage, and greatly reduce the formation water-sensitivity and water-blocking damages. It is also environment- acceptable without any toxic materials. The completion fluid has been applied in 15 horizontal wells in Ordos Daniudi gas field. The results of applications showed that the skin factors of all wells obviously decrease, especially in Well DX-1, the skin factor decreases to -2.3, and the Shan-1 formation has firstly got a good production without any stimulation treatments. The productions of all the wells are more than double times than those of former adjacent wells.