bluuebunny/crossref_metadata_2025_split huggingface dataset:
Maximising Oil Recovery of a Thin Oil Rim through an Optimised Field Development Plan
Authors: Garimella Sai , Harris Jeremy , Kalbani Ali , Lamki Ali , Khabouri Khalid 
Published: September 2011

Abstract
PDO operates many oil fields in Oman and maintains a periodical update of Field Development Plans (FDP). This paper presents a case study of one such green field where a FDP was performed that proposed numerous development wells targeting a thin oil rim overlain by a gas cap in two clastic transition-zone reservoirs. When drilling commenced, surprises were encountered such as steeper flanks, lower gross rates, higher water cut, faster pressure depletion & uncertain facies distribution. A comparison of earlier models against actual results lead to revisions mainly in vertical compartmentalization, reduced horizontal & vertical permeability. This severely impacted achieving business targets, and sub optimal use of drilling resources & surface facilities.
A new FDP Study was initiated to understand the performance and provide a revised development strategy under pressure depletion conditions. The study also evaluated the merit of installing gas lift and the impact of gas cap pressure maintenance. Revised static & dynamic models were built with the current understanding from wells drilled since the previous FDP. The simulation model was history matched with field production & pressure data and then used to identify future well locations and optimum placement within the oil rim. Additionally, the numerical model was used to assess multiple development options such as oil gains arising from gas lift installation, assessment of an additional high-pressure gas compressor for deeper gas-lifting and an additional gas export pipeline.
A fit-for-purpose uncertainty analysis of static and dynamic parameters was then undertaken to understand the range of uncertainty on field ultimate recovery. Screening of gas cap pressure maintenance resulted in a sizeable incremental oil volume over the depletion development, thus paving the way for future detailed concept selection of pressure maintenance field development. The study also resulted in identification of future infill well locations, immediate need for installation of gaslift and negated the need for an additional high pressure compressor & invalidated an additional gas export pipeline.
Robust static & dynamic models were built through multiple iterations to provide a guiding tool for future development planning. The adopted methodology described in this paper to evaluate the various development aspects is generic and could be useful in typical field developments.
Completion and Stimulation Challenges and Solutions for Extended-Reach Multizone Horizontal Wells in Carbonate Formations
Authors: Jackson Alfred , Jorden John , Al Marzouqi Mohamed Abdulla , Al Mahri Ali Eissa , Keller Stu , Shuchart Chris 
Published: September 2011

Abstract
To develop a giant carbonate oil field offshore Abu Dhabi, more than 300 wells are planned to be drilled from 4–6 artificial islands. Current plans are for these wells to be linear maximum reservoir contact (MRC) wells having horizontal completion intervals of 10,000 ft. A significant number of the wells will be extended-reach (ER) wells having measured depths exceeding 20,000 ft, and a number of the wells will have measured depths greater than 30,000 ft. One of the main challenges for these linear MRC wells is achieving adequate acid stimulation over the 10,000-ft completion interval. This paper discusses completion and stimulation options for these wells. Several of these options are illustrated by two 10,000-ft-completion-interval linear MRC pilot wells that have been drilled, completed, and stimulated from existing wellhead platform towers. These pilot wells were completed with preperforated liners equipped with ten swell packers. The stimulation treatment was performed using coiled tubing and a radial jetting tool. The completion design for a third linear MRC pilot well is also discussed. This well has been designed with a solid liner containing more than 15 swell packers and more than 35 inflow control devices (ICDs). The stimulation treatment will be performed through the ICDs. The paper also discusses a new concept for completing these types of wells using ICDs and acidizing check valves.
Evolution of Tight-Gas Fracturing Methodology in the Lower Paleozoic Sandstone Formations of Saudi Arabia
Authors: Al-jalal Ziad , Ramsey Lee , Gurmen Nihat , Kalinin Daniel 
Published: September 2011

Abstract
The lower Paleozoic Sandstone Formations in Saudi Arabia range from as deep as 20,000 ft in the South Ghawar and Rub'Al-Khali to less than 12,000 ft in the northwest. The deeper, tight-gas projects in the South Ghawar and Rub'Al-Khali have seen the highest activity since 2006. They are the subject of this review in light of four key wells. The targeted lower Paleozoic formations in these wells are Sarah, Qasim, and the Rhuddannian sandstones in the Qusaiba formation. The Sarah and Qasim formations are sandstones while the Qusaiba is interbedded sandstone and shale. The high pressure, high temperature (HPHT) environment in these reservoirs poses serious technical challenges that must be overcome when hydraulic fracture stimulation is attempted.
Specific challenges to fracture treatment design in these deep, lower Paleozoic intervals include proppant selection, interaction of fracturing fluid with the formation, interaction of fracturing fluid with drilling mud, fracturing fluid clean-up and load recovery. The four key wells show an evolution in the design methodology to meet these technical challenges. The evolutionary steps take into account geological, geomechanical, and petrophysical analyses that are calibrated with field data as the project matured. The accompanying lab work has also led to permeability profiles, well-calibrated stress regimes, and, overall, an enhanced understanding of these complex reservoirs. In turn, better reservoir understanding has improved the completion strategy.
The four key wells provide a detailed account and up-to-date documentation of the experiences gained in the last four years. Early on, a fluid selection strategy was developed based on the fracture gradient. As field data became available, geomechanics studies determined that fracture confinement was the result of a change in the stress regime. Finally, the need for multistage fracturing was established to optimize production. The lessons learned from these experiences have guided future exploration activities in the area.
Alternate Deployed Systems Application Guide
Authors: Bebak K. T. , Wisnewski Matt 
Published: September 2011

Abstract
Interest in alternative deployment methods for electrical submersible pumps has been growing in recent years. The drivers are to decrease intervention time and rig cost, to replace offshore workover rigs in environmentally sensitive areas and in remote areas with no access roads and to open the opportunity for subsea intervention. Many new technologies are being brought to market in an effort to meet the varying needs of operators around the world. Deciding upon the most technically and economically effective solution will be critical to an operator's ultimate success.
This paper will investigate a number of different deployment methods, such as conventional tubing, coil tubing with external power cable, coil tubing with internal power cable, power cable deployed, thru tubing conveyed, and wireline deployed. Some of these technologies have installation histories; some are still in their infancy Advantages and disadvantages as well as application parameters for each deployment method will be discussed. In addition, this paper details operational use of a number of the more prevalent methods in use today. The information is summarized in a key criteria guide and the bibliography will provide a useful listing of key sources for more detailed information.
The data contained in this paper will assist operators in choosing the most effective and reliable alternate deployment methods for their particular application. Information from various operators has been compiled to provide actual field usage data to support the implementation of alternate deployed systems
Evolution of Petrophysical Data Management in Saudi Aramco
Authors: Al-Ghamdi Turki , Al-Ali Hussein , Zahdan Ghassan , Al-Nahwi Ibrahim , Tjwan Tjan , Readean Muhammad 
Published: September 2011

Abstract
Well log data is used by exploration and producing (E&P) professionals to locate new well locations, conduct reservoir characterization studies, optimize well placement programs, enhance fluid monitoring plans and improve well completion strategies.
In response to the increased worldwide demand for oil and gas, Saudi Aramco has tripled its rig count. The resulting increase in well data has introduced new log acquisition and processing challenges. Saudi Aramco recognizes the importance of well log data management as a significant mission required to address the needs of E&P professionals to obtain high-quality well log data at any time and in many different formats.
Saudi Aramco started collecting log data with the first wells drilled in the 1930s. Over time, both the data types and data formats have changed with the introduction of new logging tools and technologies. Tracing the development of petrophysical data management through these years will help us to define our future vision and honor the lessons and best practices learned in the past.
In contrast to early paper-based and more recent digital log management systems, various groups at Saudi Aramco have jointly developed new systems that provide real-time data delivery from the well head to the desktop. These new systems allow well log service providers and E&P professionals to work collaboratively within an efficient, unified data management environment that improves both data quality and efficiency. New automated and semi-automated workflows reduce data delivery times, improve data quality, and log data is now easily distributed in a variety of formats to different end-user systems. The new system also provides time-based workflow monitoring, allowing managers to review internal performance and to gauge the performance of logging vendors against service level agreements.
Challenges in Attracting and Retaining Females in the Oil Industry to Meet a Diverse, Equal, and Inclusive Workforce
Authors: Wafa Yasmine 
Published: September 2011

Abstract
Gender is a business issue, not a "women's issue". The under-use of women's talent has an impact on the bottom-line. Organizations that see women not as a problem but as a solution and treats them not as minority but as full partners in leadership are the organizations that are able to make use of their full potential.
An organization's success and competitiveness is realized when it can successfully manage a diverse and inclusive workforce. The oil industry has been historically a male-dominated sector. For example, per the European Labor Force Survey, females comprise only 9% of UK engineering professionals, 18% in Spain, 26% in Sweden, and 20% in Italy.
Companies are often not ready to seamlessly absorb women into the oil sector, especially in the Middle East, due to many factors. General issues include females' dual life style (work and home) roles, accommodation for females, challenging work hours, and feeling insecure and unsafe in remote locations. Middle Eastern-specific issues include culture and religion; for example, a family's acceptance of their daughter/spouse working on a rig among male colleagues and spending nights and weeks away from the family house.
Oil companies are now focusing more on targeting female engineers to bring diversity to the oil industry. Those selected engineers are required to undergo certain orientation and training programs that should help them get harmonized in the industry.
The goal is an approach to gender that includes both halves of the human race. The aim is a new kind of "bilingual" leadership, one that maximizes the abilities and potential of both men and women by recognizing the competitive advantages of our complementary skills and natures. Successful integration of women would ensure greater benefits for the oil industry and create a more equitable society. Such integration is not easy but, when done well, it can have a transformative effect. This paper does not take the view that women are better than men. It takes view on how to capitalize on both genders in an organization. It will discuss issues and solutions for this new direction of the industry.
Kidan Sour Gas - Close Upstream Collaboration between Shell and Saudi Aramco Leads to Improved Understanding of a Complex Sour Gas Field
Authors: Briner Andreas , Holstege Gijs C. , Al-Nasser Kadhem , Daou Elie , Wood Peter 
Published: September 2011

Abstract
The South Rub Al-Khali Company Limited (SRAK) is an incorporated Joint Venture between Shell and Saudi Aramco to explore for non-associated gas and associated liquids in the South Rub'Al-Khali Basin in the Kingdom of Saudi Arabia. SRAK's contract area includes substantial volumes of ultra-sour gas in structures known collectively as Kidan. These were discovered in the 1960's by Saudi Aramco and have been appraised with several wells since then but not developed thusfar.
Alongside the exploration campaign targeting the deeper Paleozoic play, the venture has carried out substantial data gathering and evaluation of the overlying Jurassic sour gas contained in the Kidan structures (Figure 1). To enable the appropriate and most cost-effective development to be selected requires a rigorous approach to project planning with focus on up-front understanding of the complexities of the reservoir.
Extensive data gathering at the front end stage of the project has therefore been a key part of SRAK's strategy resulting in high quality datasets from two wells located on the Kidan North structure and a well on the Kidan South structure have been acquired. These data include core, openhole logs, fluid samples and production test data.
Underbalanced Drilling (UBD) as a Tool to Test Tight Gas Plays – An Example from the Empty Quarter, Saudi Arabia: Drilling and Reservoir Characterisation Lessons
Authors: Al-Maashari Yousuf , Briner Andreas , Axon Andrew , Wevers Adrian 
Published: September 2011

Executive Summary
The South Rub Al-Khali Company Limited (SRAK) is an incorporated Joint Venture formed by Shell Saudi Ventures Limited (50% share) and Saudi Arabian Oil Company (50% share) to explore for non-associated gas and associated liquids in the South Rub'Al-Khali Basin (Empty Quarter) in the Kingdom of Saudi Arabia.
This paper discusses specific data acquisition strategies that have been developed to address the challenges of deep wells in tight reservoirs in remote and harsh environments. While drilling the first three wells SRAK has gone through a very steep learning curve with respect to well data acquisition and integration. It also allowed optimising the data acquisition strategy for future wells that SRAK was planning to drill.
As a direct result of this initial work, and the experience gained by other wells drilled in the Rub' Al-Khali, SRAK realised that the traditional approach and formation evaluation using static well data gathering was not entirely satisfactory. Industry experience also showed that tight gas exploration and appraisal wells historically involved lengthy multi-year multi-well programs due to inconclusive results from static logging, coring and well testing operations.
In line with Shell's global initiative to use underbalanced drilling (UBD) for tight gas exploration and appraisal, UBD was implemented in SRAK's fifth exploration well in the Rub'Al-Khali. The deeper Palaeozoic reservoirs in the Rub'Al-Khali are known to be commonly tight and susceptible to near-wellbore formation impairment during conventional overbalanced drilling. UBD offered a possible solution for better quality reservoir evaluation and demonstrating any un-impaired potential flow. In other prospects, previous conventional drilling, stimulation and well clean-up had typically failed to unambiguously characterise pay and produce hydrocarbons to surface.
UBD drilling operations were designed and implemented with the support and expertise of the shareholders. Both internal and external subject matter experts supported operations. Whilst numerous UBD specific drilling related aspects were understood pre-drill, significant uncertainty remained around data acquisition and interpretation during UBD drilling operations.
The SRAK UBD project was safe and successfully executed as per the drilling program. Due to the UBD operations there was no ambiguity on presence and mobility of hydrocarbons, thereby avoiding SRAK the completion, fraccing and testing cost which are far higher than the UBD expenditure.
The well SRAK-5 offered firsthand experience to the SRAK team to assess the advantage and disadvantage of UBD operations on reservoir characterisation. This paper aims to capture SRAK's learning in UBD drilling and reservoir characterisation.
Identifying Stress Transfer in CSS Reservoir Operations Through Integrated Microseismic Solutions
Authors: Prince Marc , Baig Adam , Urbancic Ted 
Published: September 2011

Abstract
Advanced seismic analysis approaches are used to examine possible correlations between various seismic characteristics and observed in-situ pressure readings as related to CSS heavy oil operations in Canada. In particular, we examined how seismic parameters such as cumulative strain, apparent volume, energy surplus, and cumulative occurrence rates can be used to identify the dynamic transfer of stress from the reservoir to generating depths, generating conditions for possible failure of the cap rock.
These techniques are not only applicable to Canadian oil sands, but potentially to any environment where significant deformation results in seismic events giving the opportunity for a real-time analysis of failure conditions.
Based on our analyses, changes in cumulative strain mimic observed pressure changes. Similarly, a resulting increase in energy surplus occurred at reservoir depth coincident with the occurrence of observed pressure spikes, followed by a subsequent increase in apparent volume and cumulative occurrence rates at shallower depth subsequent to the observed pressure spikes.
Our observations suggest that advanced seismic analysis techniques can be used to potentially identify the transfer of strain and stress from the reservoir to shallower depths and provide the potential to provide real-time feedback mechanism on reservoir behaviour based on observed microseismicity.
Intelligent Fields: Industry's Frontier & Opportunities
Authors: AL-Dhubaib Tofig A. 
Published: September 2011

Abstract
Digital Field capability is at the leading edge of the Oil & Gas industry. This capability is a result of continual advancements and integration of well technologies, communications, process control, and E&P computing technologies. Digital Field capabilities enable the integration and use of surface and subsurface real time data, to optimize upstream assets and profitability. This capability has been given different names, such as Intelligent Fields, Smart fields, Digital Oil Field of the Future, integrated field and Integrated Operations. In Saudi Aramco, this capability is being leveraged through four major projects: "Real-time Drilling Operations" for optimal drilling; "Geosteering" for optimal well placement within the reservoir; "Intelligent Fields" for optimizing reservoir management, production and production operations; and "Event Solutions" for optimal field development. Throughout this paper, the term "Digital Field" will be used as the nomenclature for this capability.
This paper provides an introduction and background on Digital Field capabilities and presents Saudi Aramco's experience in leveraging them in key upstream business processes. The paper also highlights areas of applications, challenges, lessons learned, values attained and the opportunities that this brings to the industry as experienced through Saudi Aramco implementations.
Environmentally Friendly Dispersants for HP/HT Aqueous Drilling Fluids Containing Mn3O4, Contaminated With Cement, Rock Salt, and Clay
Authors: Kar Yusuf , Al Moajil Abdullah M. , Nasr-El-Din Hisham A. , Al-Bagoury Mohamed , Steele Christopher D. 
Published: September 2011

Abstract
Dispersants are widely used in drilling fluids to prevent solids flocculation and to control the rheological properties of the fluids. There is high demand for effective, thermally stable and environmentally friendly dispersants for HPHT drilling fluids. This work was undertaken to investigate the use of environmentally friendly dispersants in HPHT aqueous drilling fluids containing manganese tetroxide (Mn3O4) as the weighting agent. The dispersants were chosen because they are non-toxic to aquatic organisms and biodegradable. The effects of cement, rock salt and clay particles as contaminants on the dispersant performance and the fluid properties were investigated. The dispersants were lab tested in high density fluids of 2.1 g/cm3 at a temperature of 200°C and pressure of 500 psi. The fluids were analyzed before and after heat-aging using rheometer, sag test, light scattering, and HPHT fluid loss.
Out of over 100 dispersants tested, two dispersants showed best performance in controlling the flow behavior of the fluids in the presence of contaminants. Dispersant A is a synthetic copolymer of maleic anhydride and acrylic acid and dispersant B is an anionic lignosulfonate. They are compatible with water based drilling fluid system having manganese tetroxide as the weighting agent (SG = 2.1) and thermally stable (150-250 °C). Both dispersants lowered the rheology including plastic viscosity and yield point before and after heat aging (200°C) when compared to blank. They show also lower sag and fluid loss values in the presence of contaminants and lowered the filter cake thickness.
A New Productivity Index Formula for ESP-Lifted Wells
Authors: Al Gahtani Abdallah 
Published: September 2011

Abstract
The productivity index, PI has been used as a measure of the potential of wells to flow at certain formation pressure drawdown. Additionally, it is used to measure formation damage and formation potential to flow capacity.
In ESP-lifted wells, the pressure is boosted by the added number of pump stages. Hence, pump curves are used to describe the outflow performance of such wells. These curves, however, were generated at test bench using water which is a single phase. Because of this, a large error in estimating the performance of oil wells as multiphase flow is pumped through. Additionally, the rate of degradation of pump performance as multiphase flow is pumped is not fully understood in different pump stage design. Moreover, these pump curves are used by ESP design software's which are commercial with limited licensing.
This paper presents a new analytical solution for precisely calculating the productivity index of ESP-lifted wells by which classical pressure traverse calculation can be made using conventional Nodal analysis software. In addition, the approach yields more accurate calculations as it can be calibrated and it eliminates the compounded error in calculation by using pump curves. This method relies on augmenting the effect of pump stages into the induced pressure changes part of the formula.