bluuebunny/crossref_metadata_2025_split huggingface dataset:
Using Real Time Automated Optimisation & Diagnosis to Manage an Artificially Lifted Reservoir - A Case Study
Authors: Cudmore Julian 
Published: November 2012

Abstract
The time taken to safely optimise a reservoir produced by artificial lift can be measured in weeks or months.
Typically the well by well process is as follows:
Well testing Amalgamation of the well test data with down hole gauge and ESP controller data Analysis of the data to find the existing operation conditions Analysis of the ESP pump curve operating point and optimisation limitations Sensitivity studies in software to assess the optimum frequency and WHP Notification for the field operations to action the changes Further well tests to verify the new production data. Analysis of the data to ensure the ESP and well are running optimally and safely at the new set points
New technology enables this process to be performed in real time across the entire reservoir or field, significantly shortening the time to increased production and enabling real time reservoir management.
Each artificially lifted well in the reservoir was equipped with an intelligent data processing device programmed with a real time model of the well. The processors were linked to a central access point where the operation of field could be remotely viewed in real time.
Each well's processor was provided with a target bottom hole flowing pressure to enable the optimum production of the reservoir. The real time system automatically compared the desired target drawdown values with the capability of the pumping system installed in each well, and automatically suggested the optimum operating frequency and well head pressure to achieve the target. Where the lift system was not capable of producing to the target bottom hole pressure, a larger pump was automatically recommended. As production conditions change the system adapted its recommended operating points to compensate and maintain target production.
This paper discusses three case studies where real time optimisation and diagnosis lead to improved production from the reservoir.
Fast Track Development --- Production Achievement from Zubair and Ratawi Reservoir in North Kuwait – Challenges and Lessons Learnt
Authors: AL-Hajeri Noura , Chetri Hom , AL-Ajmi Hussain 
Published: November 2012

Abstract
North Kuwait had discovered several deep reservoirs during 1960s which were not considered for development production till 2010 because of higher priority given to the major reservoirs such as Mauddud and Burgan. Zubair and Ratawi are two such new reservoirs, taken up for fast track development since last 2 years.
In order to achieve the production target for the asset, ZU/RT need to be brought to production. A complete evaluation of all geological/ Geophysical data was done for all penetration through ZU/RT. All testing results available during the exploratory wells were comprehensively gathered and evaluated. Based on the data, fast track well release, drilling & completion were initiated. The objective was to gain production as well as data to reduce the uncertainty for further development and reservoir modeling work. The initial results indicated tremendous challenges in terms of fluid regime as well as reservoir rock properties.
The production, at the beginning of the project, was zero, which has now been increased to about 20 MBOPD within a year. Integrated team work and calculated risks helped to achieve this milestone.
The paper aims to share the challenges and the lessons learnt during the production delivery from the new reservoirs in North Kuwait.
New Technology Drillpipe for Critical Sour Drilling with First Sour Service Friction Welds
Authors: Jellison Michael , El-Rayes Kosay , Fraser Scott , Al-Khanferi Nasser 
Published: November 2012

Abstract
As the severity of sour drilling applications has increased the need for drill stem materials resistant to Sulfide Stress Cracking (SSC) has accelerated. This is especially true in the Middle East with some of the most severe H2S environments in the world. Sour service drillpipe, built with SSC resistant tubes and tool joints, has been available for some time. The friction welds joining the tubes and tool joints were not SSC resistant. This has been acceptable for many sour applications since the weld is not the high stress area of the drillpipe and because the operator has some control over the environment through the drilling fluid properties and additives. As more severe H2S environments were identified for exploration, it became apparent that a fully SSC resistant drillpipe system including the friction welds was necessary. This paper presents the successful development of SSC resistant friction welds for critical sour applications. It describes the engineering and manufacturing philosophy, laboratory testing procedures and results and applications for the SSC resistant drillpipe. Since NACE MR-0175 does not cover friction welds the engineering team developed unique and innovative criteria and testing procedures. A new patent pending four point bending test procedure and fixture were develop that employed unpolished samples that represent the surface finish of the product in service, unlike polished samples typically used in NACE TM-0177 testing. This paper provides background information on the evolution of sour service drillpipe and reviews case histories where sour service drillpipe has been successfully used including the new pipe with SSC resistant friction welds. A preview of some vital planning considerations for an upcoming world-class ERD well in Saudi Arabia with high H2S concentrations is also included. The paper can benefit drilling engineers involved in critical sour drilling operations in the Middle East and other world regions.
Simultaneous Well Stimulation and Scale Squeeze Treatments in Sandstone and Carbonate Reservoirs
Authors: Jordan M. M. 
Published: November 2012

Abstract
In many oilfields the relatively small number of high-cost, highly productive wells, coupled with a carbonate and or sulfate scaling tendency (upon waterflood breakthrough of injected seawater) requires effective scale management along with removal of near-wellbore damage in order to achieve high hydrocarbon recovery.
The nature of the well completion strategy in new fields such as frac packs for sand control and acid stimulation for carbonate reservoirs had resulted in some wells with higher than expected skin values due to drilling fluid losses, residual frac gel, fluid loss agents, and fines mobilization within the frac packs where applied.
The paper will present how the challenges of managing impaired completions and inorganic scale forced innovation in terms of when to apply both stimulation and scale inhibitor packages to sandstone and carbonate reservoirs. This paper will outline a novel process for non-conventional batch chemical applications where bullhead stimulation treatments have been displaced deep into the formation (&lt;20ft) using a scale inhibitor overflush. Not only does this benefit the stimulation by displacing the spent acid and reagents away from the immediate wellbore area, but the combined treatment provides cost savings with a single mobilization for the combined treatment. The paper will describe the laboratory testing that was performed to qualify the treatments for both sandstone and an HP/HT gas condensate carbonate reservoir. The lessons learned fromcarbonate corefloodevaluationunder HT/HP conditions when appling stimulation fluids with and without scale inhibitor present in the treatment stageswill be presented.
Many similar fields are currently being developed in offshore Brazil, West Africa and Middle East, and this paper is a good example of best-practice sharing from another oil basin.
New Project Management Approach for Offshore Facilities Rehabilitation Projects
Authors: El-Reedy Mohamed Abdallah 
Published: November 2012

Abstract
All the offshore facilities for most oil and gas companies are matures now as most of the offshore platforms were constructed from 1960 with life time over 50 years. Therefore, most of the owner companies start to perform a rehabilitation projects for the structural, mechanical, piping, electrical and all the other facilities to maintain then to have a safe longer life and to comply with the recent standard and technical practice. Therefore, the project strategy for this type of brown field project is totally different than the applied strategy for green field for a new offshore platform.
In these type of projects there are many stakeholders to manage that influence the project as the endeavor users are usually have a higher expectation from these projects, In addition to that the new facilities will use a new technique match with the up to date technology.
This paper will present the nature of project management for this type of projects and the challenges that faces the team along the project life cycle. The new approach for the whole building commissioning system technique will be discussed as a solution that cover the pitfall for applying the normal project management procedures in the brown field for oil and gas projects.
Successful Application of a Fit-for-Purpose Acid Program in the Tengiz Field
Authors: Ussenbayeva K. , Utebaeva D. , Molesworth G. , Dunger D. , Howery R. , Akwukwaegbu C. , Salikhov T. , Kamispaev A. , Zielinski M. , Yakovlev T. , Savin A. , Aglyamov M. 
Published: November 2012

Abstract
Tengiz is a unique, super-giant oil field located in western Kazakhstan that is characterized as a fractured carbonate reservoir with high concentrations of H2S. It is operated by TengizChevroil (TCO). Current production is ~ 530,000 BOPD from 70 active producing wells. As part of an effort to increase the field's production output, a workover and stimulation program was initiated in 2011 after a hiatus of more than five years from such activities.
A sizeable part of this workover effort was a matrix acid stimulation program which took lessons learned from earlier acid stimulation campaigns in the Tengiz Field to develop a modified acid stimulation treatment design. The result of this most recent program was a significant and sustained response in well productivity.
The key components of the 2011/2012 acidizing program include: 1) increased acid volumes ranging from 50-100 gal/ft and 2) an acid diversion system that included the use of a viscoelastic diversion acid and degradable fibers.
Another factor that supported the success of the acid stimulation program was the involvement of a multi-disciplinary team that addressed both candidate selection and acid stimulation design.
The TCO 2011/2012 Acid Program has shown incremental improvement in all 19 wells stimulated to date. The average initial incremental gain following stimulation is ~4, 240 BOPD per well and the overall improvement in the Productivity Index (PI) has more than tripled. Post-stimulation production logs have confirmed improvement in the production profiles, indicating the acid diversion methods are having a positive impact.
The Use of a Formation Tester to Characterize Permeability and Vertical Communication across Stylolite Zones in a Carbonate Reservoir - Case Study
Authors: Al-Amrie Omar Yahya , Saad Mohamed Ahmed , Marzouqi Khalid Ibrahim , Kshirsagar Atul , Coskun Sefer B. 
Published: November 2012

Abstract
Quantifying the vertical permeability and sealing capability of the stylolite zones in a Middle East carbonate reservoir is critically important for the enhanced recovery, water coning, perforation policy and well-placement choices. A wireline formation tester was used to perform four vertical interference tests (VIT) in a newly drilled well. The objective was to obtain permeability, permeability anisotropy and vertical communication across the stylolite zones.
The formation tester was configured with a straddle packer, acting as a source of fluid flow, and two observation probes that recorded the pressure disturbances originating from the source. The formation testers were strategically placed so that the stylolite zones were located between the two observation probes. The simultaneous analysis of pressure transients from the straddle packer and the first probe provided the permeability and the permeability anisotropy of the main reservoir units. The vertical communication across the stylolite zones was evaluated by analyzing the pressure transients from the second probe.
The results of the four VITs indicate varying degrees of vertical permeability across the stylolite zones, implying none have the sealing capability for fluid flow. Reservoir simulation studies were performed to evaluate the impact of stylolite sealing capacity on field performance. Results show that the model cannot match the actual production and pressure data if the stylolite zones were sealing. Therefore, this confirms that the stylolite zones in this field have no sealing capacity as shown by the VIT test results.
The result of this study concludes that VITs can provide valuable dynamic data for reservoir characterization and could be extended in a field-wide approach to evaluate the lateral continuity of the vertical permeability variation across the stylolite zones. The results will be used in determining the perforation and well-placement policy and modeling the enhanced oil recovery studies.
Fracture Growth Monitoring in Polymer Injectors- Field Examples
Authors: Shuaili Khalfan , Cherukupalli Pradeep Kumar , Al-Saadi Faisal Salim , Hashmi Khalid Al , Jaspers Henri F , Sen Subrata 
Published: November 2012

Abstract
The objective of injecting polymer in brown fields is to increase recovery beyond primary and secondary recovery mechanisms. However, generally it is difficult to achieve adequate (viscous) polymer injectivity in depleted sandstone reservoirs without fracturing. Therefore, monitoring fracture propagation is required in order to control vertical conformance and areal sweep and avoid early polymer breakthrough.
Different surveillance methods are used to identify the existence and properties of fractures in polymer injectors. Pressure Fall off (PFO) survey data in conjunction with time-lapse temperature surveys are extensively used to determine the fracture dimensions. PFO tests in Polymer injectors have particular characteristics since they are influenced by shear-dependent viscosity seen in non-Newtonian fluids. A specially developed Injection Fall-off (IFO) model was used to determine fracture dimensions which is based on exact semi-analytical solution to the fully transient elliptical fluid flow equation around a closing dynamic fracture developed by Shell, (Van den Hoek 2005), as static fracture models are inadequate.
This paper presents different phenomena in polymer injection seen in PFO tests such as fracture closure, the effect in-situ polymer rheology and the detection of the polymer front. The paper demonstrates the effect of liquid-level drop observed in PFO survey in under-pressured reservoirs and its impact on determining fracture and some other reservoir properties. It also shows how plot-overlays of time lapse PFO's for a particular well can be used to track changes in fracture dimensions. All of these are illustrated by a number of field examples of polymer PFO which also demonstrate the calculated fracture dimensions from the data. Finally, some recommended best practices are suggested for fracture monitoring.
A Diagenetic Diagram as a Tool for Systematic Detailed Characterization of Carbonate Rocks: Applications to the Diagenetic Evolution of Hydrocarbon Reservoirs
Authors: Inês Nuno , Azerêdo Ana , Bizarro Paulo , Ribeiro Teresa , Nagah Adnan 
Published: November 2012

Abstract
Carbonate reservoirs are commonly heterogeneous and their reservoir quality results from complex interactions between depositional facies and diagenetic processes. The Diagenetic Diagram is a powerful tool that helps in the characterization of the diagenetic processes that have affected the reservoir. From this knowledge, it is possible to significantly improve the understanding of the reservoir's pore system and permeability distributions, which are key factors for development optimization and production sustainability.
A multi-scale and multi-method study (petrography, blue-dye impregnation, selective staining and porosity determination) of Middle Jurassic carbonates from the Lusitanian Basin (Portugal) has been undertaken, to find the best systematic approach to these reservoirs. It has involved thorough diagenetic characterization of each lithotype (lithofacies, texture, porosity, qualitative permeability assessment and diagenetic evolution). The study area was selected based on its excellent and varied exposures of carbonate facies and availability of core.
Methodological and terminological challenges were faced during the study, especially dealing with data coming from several scales (macro, meso, and micro). In order to overcome these challenges, a diagenetic diagram was developed and applied to the selected rocks. It is a tool that allows the integration of data coming from outcrops, hand samples, cores, cuttings, thin sections, and laboratory experiments.
This is carried out in a dynamic, guided, systematic, and rigorous way, enabling the evaluation of the relationship between facies, diagenetic evolution and pore systems. The latter are characterized regarding size, geometry, distribution, and connectivity. This enables the identification and characterization of permeability heterogeneities in the rocks. It was concluded that the main porosity class (i.e. secondary) was created by diagenetic processes.
The proposed method has strong application potential for: detailed characterization and understanding of porosity and permeability in carbonate reservoirs, from a diagenetic evolution and fluid flow perspective (e.g. SCAL and pore system description); definition of diagenetic trends for modeling petrophysical properties and rock types. In this regard, the method is being applied to a Valanginian carbonate reservoir in Kazakhstan, and some preliminary results are presented in this paper. Refining this technique may be helpful for similar carbonate studies, enhancing the results of typical diagenetic studies by improving the characterization of reservoir properties at various scales, thus contributing to a more sustainable exploitation of hydrocarbon reservoirs.
H2S Early Notification System for Production Pipelines: A Pilot Test
Authors: Hirezi George J. , Al-Khelaiwi Faisal T. , Al-Khamis Mohammed N. 
Published: November 2012

Abstract
The produced fluid of an oil field located in the Eastern Province of Saudi Arabia contains relatively high levels of H2S. A pilot test was conducted by Saudi Aramco to install a wireless gas detection system along an oil pipeline in this field. The pilot test objectives include:
Determining the communication availability and reliability of the remote wireless sensors where extending hardwired and fiber optic networks proved impractical and expensive. Evaluating the usefulness of this system for early notification of toxic gas releases or pipe leaks in and around critical geographical areas by alerting the console operator and via e-mail and Short Message Service (SMS).
The piloted system includes six wireless sensors separated at an equal distance along a 2 km oil pipeline. The sensors communicate wirelessly with a gateway receiver located in a shelter at a producer site. The wireless gateway is integrated with an existing Supervisory Control and Data Acquisition (SCADA) system by connecting it serially to a Remote Terminal Unit (RTU). Accordingly, the sensor's measurement and diagnostic data is monitored by the operators at their console in the control room. The same data is also accessible to the engineers at their desktops for real time monitoring and long-term archiving purposes via the OSI PI system.
The test results of the year-long pilot indicated that the gateway receiver demonstrated very high reliability and availability since it had no failures during the test period; however, initially some of the wireless sensors had experienced minor but recoverable communication errors.
This paper describes the details of this pilot test and discusses the difficulties encountered during the project's testing phase along with the actions taken to mitigate such problems, and subsequently improve the overall reliability and availability of the wireless communication.
Advanced Utilization of Downhole Sensors for Water-cut and Flow Rate Allocation
Authors: Al-Amri Meshal A. , Al-Khelaiwi Faisal T , Al-Kadem Mohammad S. 
Published: November 2012

Abstract
Downhole pressure and temperature sensors have been installed either separately as stand-alone sensors hanged on the production tubing of a well or jointly with Electric Submersible Pumps (ESPs) or Intelligent Well Completions (IWC). However, their utilization thus far has been limited to static/flowing bottom-hole pressures measurement for buildup/drawdown pressure tests analysis or ESP/intelligent well performance monitoring.
Eighty-eight (88) wells located offshore Saudi Arabia have been equipped with ESPs combined with downhole pressure and temperature sensors installed at the intake and discharge of the pumps. Each well was equipped with a surface coriolis meter to measure the total liquid flow rate and water-cut assuming that the well's production will be maintained above the bubble point pressure. However, the coriolis meters’ readings have become erroneous ever since the wells’ flowing wellhead pressure declined to and below the saturation pressure due to the flow of liberated gas through the meters. In order to compensate for the meters’ measurement deviation, wellhead samples had to be collected and analyzed to determine the wells water-cuts where the total flow measurement was still acceptable. Alternatively, other means of multiphase flow rate measurements were used. This has proven to be costly and time consuming.
This paper proposes a technique which uses real-time data transmitted from existing surface and subsurface sensors to calculate the water-cut and flow rate of each well and avoid the risky and costly field trips for wellhead sample collection and analysis. In addition, the paper describes an innovative technique to estimate the error in the measured density and calculated water-cut based on the bubble point pressure which accurately determines the application envelope of this method. The paper provides examples to illustrate the validity of the proposed technique in comparison with measured and sampled water-cuts which were collected above and below the bubble point pressure. Furthermore, the paper sheds light on the main issues impacting the method's reliability.