bluuebunny/crossref_metadata_2025_split huggingface dataset:
Artificial Lift Performance Enhancements by applying Root Cause Failure Analysis
Authors: Lapi S. G. , Arisman B. , Johnson M.  E. 
Published: May 2016

Abstract
This paper describes the use of a Root Cause Failure Analysis (RCFA) process to improve artificial lift systems performance: Electric Submersible Pumps (ESP) and Progressing Cavity Pumps (PCP). The subject field is remote and heavy oil environment with a wide range of production rates, fluid types, and reservoir conditions. Conditions are challenging for ESPs including severe emulsions at high water cuts, and the conditions are challenging for PCPs with relatively deep pump landing depths and high water cut. The field contains more than 800 active wells with continuous drilling operations. Pump repairs are a major part of workover rig activity. Early in the life of the field, failure rates were rapidly increasing. Collaborative efforts were established among the vendor and functional teams to address failures. The RCFA process was established with the objective to evaluate every failed pump system to determine the reason for failure, identify contributing factors, and monitor trends. The RCFA process evaluates pump performance, well test history, well intervention history, and artificial lift designs. Another key aspect of the RCFA review process is to evaluate compiled equipment teardown information. The RCFA meetings are used to share information and insure open communication among the parties. The meetings are also used to identify additional data requirements to help determine a root cause of failure. The RCFA process has led to revised equipment design and selection criteria, helped to develop new surveillance tools and processes, enabled optimized operational envelopes, and improved installation procedures. These processes and tools can be transferred and implemented successfully for other projects to help maximize value of the asset. The RCFA process was fully implemented and consistently applied since 2006 and has helped to reduce the failure frequency more than 70 % on ESPs and more than 50 % on PCPs, despite the fact that ESP population has more than tripled and PCP installations has more than doubled.
Revisiting Reaction Kinetics and Wormholing Phenomena During Carbonate Acidizing
Authors: Qiu X.  W. , Zhao W. , Dyer S.  J. , Al Dossary A. , Khan S. , Sultan A. S. 
Published: May 2016

Abstract
Wormholing during matrix acidizing of carbonate reservoirs is known to be predominantly mass transfer limited. Mass transfer coefficient, controlled by the fluid injection rate andthe acid diffusion coefficient, dictates the speed and profile of the wormholes.
Injection rate is easily obtained from the job execution, whereas the diffusion coefficient is intrinsically a hidden parameter of the fluid and reaction conditions. Acid diffusion coefficient data used in modeling the wormholing processes are commonly obtained at 1000 psi system pressure, which is too low to represent realistic reservoir conditions. In order to properly quantify the acid penetration inside the formation, the diffusion coefficient of acid acquired from high-pressure reservoir conditions should be used.
In this study, we investigate the effects of diffusion coefficients of HCl acid as it reacts with calcite. We use a rotating disk apparatus to obtaine the CO2-impacted kinetics at downhole conditions. The test results show that the diffusion coefficient of the HCl acid is much lower at high pressure than low pressure at the same concentration due to the impact of CO2 produced by the HCl-carbonate reaction. At higher pressure, more CO2 tends to stay in an aqueous phase, which slows down the reaction of HCl and the carbonate formation. For example, at 150 °F, the diffusion coefficient of 15% HCl at 3,000 psi reduced 50% of its original value when at 1,000 psi of 15% HCl.
This new set of kinetics data is then implemented in a 3D wormholing model to predict wormhole morphology and penetration velocity. The model uses a CT-scan rendered porosity field to capture the finer details of the rock fabric. Simulation results of fluid flow coupled with reaction provide new insights on how acidizing design models should be improved to more accurately quantify wormhole penetration, which then leads to more accurate production forecasts.
Satellite derived Bathymetry and Digital Elevation Models (DEM)
Authors: Siermann J. , Harvey C. , Morgan G. , Heege T. 
Published: May 2016

Abstract
In 2010, Qatar Shell Upstream International B.V. (QSUI) re-entered Exploration in Qatar focusing on the relatively deep conventional Pre-Khuff gas plays with a view to discover additional hydrocarbons in the State of Qatar. In order to support Qatar Shell with the execution of onshore and offshore seismic programs, satellite imagery was used extensively to derive added value products in terms of shallow water bathymetry, seabed classification and onshore digital elevation models (DEM).
For the offshore bathymetry and seabed classification products, 2m resolution multispectral WorldView-2 satellite scenes were processed following a data processing chain including the correction of atmospheric adjacency (increased radiance over water due to reflection of photons by the nearby land and their further scattering in the atmosphere), water surface and water column effects. The resulting offshore products had a spatial resolution of 4m and covered an area of ~700 km2. For the onshore elevation product, a 50cm WorldView-1 stereo image pair was processed using a photogrammetric stereo vision algorithm to generate a 1m spatial resolution DEM over an area of ~450 km2. The accuracy and quality of these satellite image derived products depend largely on the optical conditions of the satellite scene, the sensitivity of the satellite sensor and the accuracy of the calibration. Three types of independent control datasets were used to assess the quality and accuracy of the bathymetry and DEM; airborne LiDAR sounding transects, multibeam echo sounding swaths (offshore) and seismic survey lines (onshore and offshore). After correction for any systematic bias, the correlation of both products with the control data was found to be very good with &lt;1m vertical error in general.
Satellite image products are recognized within QSUI as a key technology to aid the planning and preparation of seismic operations and site evaluation by improving hazard identification and reducing field risk exposure early on in the project life cycle. In addition, cost savings were realized compared to more costly traditional acquisition methods. The seismic field conditions were assessed relatively quickly compared to the time frame required for traditional methods. This allowed the data to be included in commercial tendering which in turn resulted in sharper bids.
In conclusion, satellite imagery in combination with the right processing techniques has the potential to provide an integrated wide area bathymetry and DEM coverage at relatively high resolution and low cost.
Reduction Of The Carbon Footprint In Ammonia Production Through Petrochemical Plant Integration In Qatar
Authors: Daghash Shaden , Benyahia Farid 
Published: May 2016

Abstract
The gas industry in Qatar is experiencing a massive growth and its energy consumption leads to significant carbon emissions specifically Carbon Dioxide (CO2). All plant operators have been required to report carbon emissions to local authorities according to international standards. However, it is not clear how carbon will be managed in the future. In this work, a potentially attractive solution for carbon management will be put forward. This work involves a case study on Ammonia production facility and the carbon footprint of the Ammonia process. The sources of CO2 investigated were from the Ammonia process itself and its main support utilities (combustion in gas turbines, steam boilers and natural gas reformers). Refering to previous work done (on Ammonia process simulation using industry standard HYSYS and process calculation using a spreadsheet), an attempt was made to recover CO2 from the process to be utilize in Urea and Methanol manufacturing. This approach was based on the concept of plant integration where Ethylene, Ammonia, Urea, and Methanol production facilities would have a certain degree of mass integration. The work highlighted the importance of the Hydrogen balance from the Ethylene facility and the extent of CO2 recovery and capture from the Ammonia facility. The results indicated that it is possible to target around 45% of CO2 produced in Ammonia manufacturing and utilize it to produce high value products such as Urea and Methanol. It was found that when excess Hydrogen is utilizaed with part of CO2 produced from Ammonia manufacturing facility, excess Methanol that is equivalent to a half a train capacity can be produced (~1424 MTPD*). In addition to that it was found that utilizing another part of CO2 with Ammonia product - that is usually gets exported - almost one train of Urea can be produced (~3728 MTPD). The concept of plant integration was found very powerful and relevant in the context of carbon management since it is known that captured CO2 in Qatar and gulf area may not be stored underground in large quantities because the geology is mainly carbonate reservoirs. The work also indicated the need to purify both CO2 and hydrogen to qualities compatible with the applications indicated. A network of hydrogen and CO2 pipelines was also highlighted in the plant integration study. This plant integration of important petrochemical processes has shown that it is possible to reduce significantly carbon emission in Ammonia manufacturing.
Mechanism and Application of Improving Heavy Oil Recovery Greatly by Solvent and Foam Assisted Steam Flooding
Authors: Jianfang Sun , Guanghuang Wu , Chuanxi Liu , Wei Li 
Published: May 2016

Abstract
The annual production reached 47.5 million tons in 2012 in Shengli oilfield, almost 96% of which was produced by CSS with low recovery factor of only 18.8%. Steam flooding as the main EOR technique isn't available for the heavy oil in Shengli oilfield because of the following challenges : the deeply buried depth of reservoirs (more than 1300m) results in low steam quality at bottom hole.high formation pressure makes steam zone narrower and hot water and condensation zone wider.the severe heterogeneity of reservoir causes steam channeling.
To improve greatly recovery factor after CSS, a solvent and foam assisted steam flooding (SFASF) pilot was carried out in Gudao Block 2 heavy oil reservoir. The oil production rate of small well spacing pilot increased from 20t/d to a peak of 101t/d, water cut decreased from 89% to 74.6%, and the recovery factor will be raised by 21.8% and up to 57.7% during SFASF.
The mechanism of SFASF was investigated. In order to reduce the steam channeling and improve steam uniform driving, N2 and foam agent were injected periodically during steam flooding. A new foam agent was developed, of which the resistance factor can always keep more than 20 under residual oil saturation at 300?. In order to improve displacement efficiency at hot water and condensation zone, A new anionic solvent was developed and injected during steam flooding so as to decrease oil-water interfacial tension and residual oil saturation. The solvent can make IFT up to 10-3mN/m at 300?. Moreover, optimum concentration of foam agent and solvent of SFASF is about 0.5% and 0.3% respectively and steam flooding is continuous with one month chemical system plug after three month interval. In order to get better effects high steam quality boiler by superheat, equal dryness distributing and high efficiency wellbore insulation technology were developed.
Combining heat with chemical is a trend to improve greatly heavy oil reservoirs recovery factor and the SFASF technique is available for more than 0.174 trillion tons oil reserve in Shengli oilfield.
Flow Modeling and Comparative Analysis for a New Generation of Wireline Formation Tester Modules
Authors: Kristensen Morten , Ayan Cosan , Chang Yong , Lee Ryan , Gisolf Adriaan , Leonard Jonathan , Corre Piere Yves , Dumont Hadrien 
Published: May 2016

Abstract
Wireline formation testing (WFT) is an integral part of reservoir evaluation strategy in both exploration and production settings worldwide. Application examples include fluid gradient determination, downhole sampling, fluid scanning in transition zones, as well as interval pressure transient tests (IPTTs). Until recently, however, formation testing was still challenging and prone to failure when testing in low-mobility, unconsolidated, or heavy-oil-bearing formations, especially with single-probe type tools. A new-generation WFT module with a 3D radial probe expands the operating envelope. By using multiple fluid drains spaced circumferentially around the tool, the new module can sample in tighter formations and sustain higher pressure differentials while providing mechanical support to the borehole wall.
We performed a detailed flow modeling-based analysis of the contamination cleanup behavior during fluid sampling with the new module. Using both miscible (sampling oil in oil-based mud) and immiscible (sampling oil in water-based mud) contamination models we studied the cleanup behavior over a wide range of formation properties and operating conditions. Comparison of the cleanup performance of the new module with the performance of conventional single-probe tools demonstrates that the new module is 10 to 20 times faster than the single-probe tools when sampling in tight formations. Finally, we also compared the new module against the sampling performance of dual packers and a focused probe.
This work is directly relevant to the planning and fundamental understanding of wireline fluid sampling. The key contributions are miscible and immiscible contamination cleanup models that include the effect of tool storage, a comprehensive analysis of contamination cleanup behavior for the new-generation WFT module with comparisons against conventional single-probe, focused probe, and dual-packer tools, and a characterization of fluid sampling conditions versus the preferred type of sampling tool.

Introduction
A logical start for any wireline formation testing (WFT) operation is a tool string design that considers the formation evaluation objectives and expected formation and fluid properties. With the current availability of an arsenal of probes having different shapes, focused probes of circular or elongated design, and dual packers, this planning stage has now become a more complex process. The recently introduced 3D radial probe (Al Otaibi et al. 2012; Flores de Dios et al. 2012) adds another choice for the engineers in planning WFT surveys.
Utilization of Onsite Nitrogen Generation Technology as a Replacement for Conventional Liquid Nitrogen for Unloading Wells: a Novel and Cost Effective Alternative with Less Carbon Footprint on the Environment
Authors: Al-Mulhim Abdulrahman K. , Al-Abdulmohsin Yousif Ahmed , Al-Khalifah Hamzah A. , Al-Shehri, Ayedh M. , El-Zefzafy Ibrahim M. 
Published: May 2016

Abstract
Nitrogen gas is one of the important consumables in demand in high volumes in the upstream oil industry. One of its regular uses is in the nitrogen unloading wells during kickoff operations to liven dead wells. Conventional methods use liquid nitrogen stored and transported in specially insulated vessels to be pumped into wells using sophisticated cryogenic pumps and equipment. Cryogenic equipment that operates at very low temperatures, poses several safety hazards such as causing cold burns when skin comes in contact with a severely cold object (liquid nitrogen is at -196 °C). This technical paper presents the successful utilization of in situ generated nitrogen gas at a wellsite as a replacement of the conventional requirement of liquefied nitrogen, storage and transportation system for liquid nitrogen, and cryogenic pumps and equipment for pumping nitrogen into the well.
The paper will discuss briefly the membrane technology used to produce clean nitrogen at wellsites by drawing atmospheric air as the raw input; and the advantages of the continuous nitrogen generation technology over the conventional liquid nitrogen system.

Introduction
Nitrogen gas is being used heavily in the oil industry for various operations. Unloading and reviving oil wells by reducing the hydrostatic pressure created by the fluid column inside the wellbore by pumping nitrogen using coiled tubing units is a main practice nowadays in oil fields. The conventional method being used in such cases is utilizing liquid nitrogen stored and transported in specially insulated vessels to be pumped into wells using sophisticated cryogenic pumps and equipment. This method poses some disadvantages such as gas consumption efficiency, high cost and limited quantities at wellsites especially in remote areas. Also, it positions serious safety concerns such as cold burns and accidents while transporting the liquid nitrogen. To overcome the disadvantages and minimize these safety hazards, this new approach of using onsite nitrogen generation by separation of nitrogen from the air by selective permeation through a bundle of hollow fibers has been trial tested in Ghawar field, Saudi Arabia, to meet the demand for high volume and eliminate the troublesome logistics and timing of supply while delivering liquid nitrogen to wellsites; especially in remote areas.
Determination of Reservoir Permeability Based on Irreducible Water Saturation and Porosity from Log Data and FZI (Flow Zone Indicator) from Core Data
Authors: Fazel Alavi M. 
Published: May 2016

Abstract
The Flow Zone Indicator (FZI) core analysis method is an accurate approach for defining different Hydraulic Units (HUs) in a well with core data, and finding accurate k-f relations for each HU according to k = Cn fxn. Determining HUs in un-cored wells from logs or geological information is the main challenge for the FZI method. Several methods have been proposed for finding HUs in un-cored wells. In many approaches, HUs are correlated with log attributes in cored wells, and this relationship is applied to un-cored wells. However, since a persistent relationship between log attributes and FZI does not exist in all litho-facies, this does not always give reliable results.
Based on a study of core and log data from several carbonate reservoirs, a practical, straightforward technique designated as the FZI-SWPHI (Flow Zone Indicator - Irreducible Water Saturation and Porosity) method is proposed. A theoretically sound relationship between FZI and Swir fe exists for a sedimentary environment. To find this relationship, FZI values from cores of the well are statistically related to the irreducible water saturation and porosity values from log data. The resulting equation, similar to the Wyllie and Rose, Tixier, Timur, and Coates equations, relates permeability directly to effective porosity and irreducible water saturation.
Unlike these general equations, however, this new equation is specific to the reservoir under investigation because constants are defined for the reservoir. The derived equation can be directly applied to wells or reservoir model grid blocks, where water saturation and porosity are known. This method is more straightforward to use and generates more precise permeability estimates with higher vertical resolution. Several examples demonstrate the accuracy and practical applications of this technique.

Introduction
The Flow Zone Indicator (FZI) method for classifying core data into Hydraulic Units (HUs) with specific FZI was introduced by Amaefule et al. (1993) and is one of the best techniques for reservoir description. This method provides accurate correlations between permeability and porosity when FZI of the reservoir rock is known. FZI is determined from core data in the cored wells and it is often applied to wells without cores through correlations with log attributes. However, existing correlation methods do not always generate accurate permeability values for wells without core data.
Production Engineering and Geoscience Integration (PEGI) as an Integrated Tool for Reservoir Surveillance and Opportunity Generation for Dukhan Field, Qatar
Authors: Negron J.  M. , Dwiyarkoro B. , Hasan W. , Abuhelaiqa A. 
Published: May 2016

Abstract
In an effort to integrate production performance and geological data, Qatar Petroleum developed a tool (PEGI) that assesses the current fluid front movement and reservoir behavior. The tool along with a collaborative review process, assists operation subsurface engineers and geoscientists in their evaluation of the reservoir performance while identifying new opportunities (e.g., by-passed oil) and data requirements.
PEGI links structural and stratigraphic reservoir models to production/injection data, well completion history, pressure and logging surveys, within a date, depth and layers database. This linkage provides continuous quality control by simultaneously and iteratively reviewing all data on the same platform in "real-time." The tool also ties surveillance activities with reservoir characterization and simulation efforts.
The process consists of developing mapping units based on geologic layers for interpreting fluid contacts and pressures. The engineering and geoscience data are integrated to guide the reservoir management through improved understanding of the flood front movement and dynamic behavior through time. New development opportunities can be easily visualized and analyzed both in 2D and 3D to better understand reservoir geometry and performance by multidisciplinary teamwork. Potential new well locations and areas of interest are flagged for further investigation. PEGI provides a solid understanding of reservoir geology and fluid dynamic behavior through visualization which supports the well placement process.

Introduction
Dukhan field is located onshore approximately 80 km to the West of Doha, the capital of the State of Qatar (Fig. 1). There are currently four oil producing reservoirs and one gas producing reservoir with Arab C and Arab D being the dominant. The field is a narrow anticline running north-south along Qatar's western coast. The dominant reservoirs are both structurally and stratigraphically complex carbonates. The Arab C reservoir was originally undersaturated while the Arab D reservoir was saturated with the presence of an initial gas cap. The development of the field has taken place in various stages since 1949, water dump injection started in 1965 and powered water injection to maintain reservoir pressure was taken up in stages starting from 1989. A gas recycling project in the gas cap started in 1998 and horizontal well drilling started in 1995 which later was adopted as the main development strategy since 2000.