bluuebunny/crossref_metadata_2025_split huggingface dataset:
Experiences and Benefits Gained through Implementation of the First Intelligent Field in Saudi Aramco (QATIF Field)
Authors: Al-Dossary Faisal M. , Al-Ghamdi Abdurahman A. , Al-Ahmari Abdulrahman S. 
Published: June 2009

Abstract
Qatif field is the first intelligent field in Saudi Aramco equipped with measurement, communication, control and software allowing real-time automated field management. The Qatif field is equipped with automated remote controls and surveillance systems due to its complex reservoir fluid characteristics, including high H2S concentrations up to 16% mole fraction.
Initially twenty multiphase flow meters were installed at Qatif field 22 drill sites, testing 96 wells. One of the MPFM units tests sixteen wells from three different producing reservoirs. (PVT) reports based on black oil models were initially used, but did not match the fluid characteristics due to the H2S presence in the produced gas, in addition to the sulfur substance in the produced fluids. The initial tests using the black oil model were showing water cut as high as 60% on wells known to have no water. Using the limited number of available PVT reports, we have generated simulated generic PVT reports for each reservoir.
To facilitate real-time well bottom pressure data and reduce the wireline interventions to collect these data, tandem gauge permanent downhole monitoring systems (PDHMS) were initially installed in 29 wells. Data was collected and used to support well flow optimization efforts to determine the maximum well deliverability, based on current BHP conditions. Further, these data supported ongoing simulation efforts within the three reservoirs through the generation of real-time isobaric maps to optimize production/injection strategies. Problems with these PDHMS included six of 29 that failed prematurely due to downhole cable failure. These gauges eliminated 62 wireline interventions a year with savings of $350M.
Safety in Qatif field is a major ongoing concern since the field has high H2S concentrations. Well sites and associated flowlines are equipped with the following: state of the art emergency shutdown systems (ESD), wellhead and valves use programmable logic controls (PLC), H2S sensors and remote controls 3. This equipment contributed to the field's zero safety incident record for the past 4 operating years.
The use of the I-Field concept has reduced field operational expenses as well as improving the overall well surveillance activities. During 2007, the operating cost in the field was reduced by over $ 1million and any lost production avoided by employing I-Field intelligent fields for the well surveillance activities. The reservoir models are being updated real time to enhance well placement as well as to optimize existing well operational strategies. Remote well controls have reduced manpower and conventional equipment requirements to operate the field while maximizing well surveillance activities.
Material Selection for Downhole Sour Environments
Authors: Moosavi Ali N , Rumash Khalid , Kadri Mostafa 
Published: June 2009

Abstract
The steep rises in price of crude and gas have led operators to increase their production, much of it through secondary recovery. The increase in production has resulted in increases in water cut and H2S which, together with other corrosive elements such as CO2 and chlorides, have caused serious concerns regarding safety and corrosion. The traditionally used steel OCTG suffer failures within a relatively short period of operation in these environments. Therefore the use of corrosion resistant alloys (CRA) is set to increase over the coming years. The cost difference between the lower and higher end of CRA can be very substantial. The traditional material selection approach has heavily depended on the use of standards and desktop corrosion rate predictions. However the confidence level with this approach is limited. A comprehensive and innovative program has therefore been adopted to address this issue. Our approach has been two fold: first we designed and manufactured a special downhole coupon holder in order to expose a number of different CRA material in a selected number of our reservoirs. Secondly, we carried out a comprehensive program of corrosion tests on a range of materials in a variety of our reservoir conditions simulated in the laboratory. The combination of field, lab and desk-top evaluation enables us to select the most technically suitable and cost effective material for each specific environment.
A total of 14 alloys from a number of manufacturers have been tested. These ranged from the L-80 carbon steel (used as reference) to the lower end CRA such as 13Cr and Super 13Cr to mid range CRA such as duplex stainless steel ton the higher end nickel-chromium alloys. The results have been very encouraging. Ten out of 14 materials tested exhibited insignificant levels of general and localized corrosion (pitting and crevice). The four which suffered corrosion higher than this level were the L-80 carbon steel reference material and most of the 13Cr alloys. Encouragingly, all the Super 13Cr alloys passed all the corrosion tests in all the environments satisfactorily. Even in the environmental cracking tests the super 13Cr alloys were successful in the majority of the tested environments. These are at the cheaper end of CRAs and using them instead of Ni-Cr alloys can make very substantial savings for the operating company, as well as proving a material which is technically far superior to the traditionally used L-80 carbon steel and provides a much longer operating life.
The field testing results were even more encouraging with the Super 13Cr alloys not suffering from cracking in any environments and, apart from the most aggressive one of the eight field testing environments, they did not suffer from any significant corrosion or pitting.
A classification of the tested alloys by test condition, based on the laboratory results is presented. This shows that for every one of the downhole environments that we have tested, there are a range of acceptable materials available.
Maximum Reservoir Contact Wells: Six Years of Performance-Lessons Learned and Best Practices
Authors: Salamy Salam , Al-Mubarak Saeed , Al-Mubarak Hassan , Al-Dawood Naseem , Al-Alawi Ahmad 
Published: June 2009

Abstract
This year marks the sixth year anniversary of the birth of the Maximum Reservoir Contact (MRC) wells in Saudi Aramco. The outstanding performance of 99 MRC wells drilled to date in different fields reflects the impact of MRC wells on improving well performance, enhancing recovery and reducing unit development costs. In view of this performance, the use of this technology will continue to be on the rise.
This paper will highlight the drivers, selection criteria, and lessons-learned from the MRC wells. It will further highlight cases of how MRC wells became the cornerstone in optimizing the development of tight reservoirs and in re-engineering mature ones. In addition, the paper will highlight the impact of MRC wells on rate sustainability and on increasing off-take levels by up to five times when compared to vertical and single lateral well completions. MRC wells not only targeted new development wells, but also extended to workover programs where low performer and dead wells were converted to MRCs. Results were phenomenal in terms of improving well productivity and delaying water and gas breakthroughs-thereby improving sweep.
Optimizing Production in Maximum Reservoir Contact Wells with Intelligent Completions and Optical Downhole Monitoring System
Authors: Al-Arnaout I. H. , Al-Buali M. H. , Al-Mubarak S. M. , Al-Driweesh Saad M. , Zareef M. A. , Johansen E. S. 
Published: June 2009

Abstract
In today's drive to improve well production and performance, more innovative methods are continually being implemented to enhance well productivity and reservoir management. By increasing reservoir contact and applying fit for purpose technologies, increased production can be attained at lower drawdown. This can be accomplished by the effective implementation of multilaterals wells. In multilateral wells equipped with active downhole control valves and downhole measurement-devices, monitoring and managing the production from each lateral is achievable. These capabilities will enhance well performance and allow better sweep; hence better recovery.
This paper describes the design, completion, commissioning, and operational experience of the world's first well equipped with intelligent completion combined with fiber-optic monitoring capabilities. Well-A is a trilateral MRC well with more than 5 km of total reservoir contact. The monitoring system for each lateral includes an optical flowmeter and pressure and temperature gauge. The readings of the flowmeter were compared to the readings against the conventional testing facilities. Production tests were conducted with various combinations of downhole valve positions for each of the three laterals to determine the optimum combination. The pressure and temperature gauges yielded excellent measurements as they were verified against conventional pressure and temperature measurements. The downhole flow rate measurements were assessed against conventional rate measurements and demonstrated acceptable results across most downhole valve positions. A comprehensive review was conducted on the optical flow meter capabilities to provide better understanding; hence, facilitate further enhancement to the technology and better production optimization capabilities. The review was utilized to develop a new system that provides better capabilities across all valves positions.
Installation for Pressure Reduction of Hydrocarbon Gases in a Near Isothermal Manner
Authors: Valente Antonio 
Published: June 2009

Abstract
New equipment designed for achieving the pressure reduction of Hydrocarbon gases in a near isothermal manner with the simultaneous recovery of its elastic energy lost during pressure reduction thermodynamic process. The equipment is consisting on utilizing a Tesla turbine which rotor is composed of several parallel plane discs rotating by boundary layer effect, induced by the moving gas drag when spirally passing parallel to those discs, associated with an electrical power generator.
During experimental tests it was found that the gas to be processed suffers a pressure reduction, by loss of energy transmitted to the rotor, in a near isothermal manner contrary to the usual equipments utilized in the actual state of the art.
Taking advantage of the said discovered singularity the equipment will be applied for pressure reduction of Hydrocarbon gases, without the temperature reduction associated if utilizing the Joule-Thomson effect and in addition will generate energy. It will also be applied in Hydrocarbon gas liquefaction, with in a first step of near isothermal pressure reduction complemented by a cryogenic stage of liquefaction where the energy required will be derived from one generated on the first step.
In the actual energetic conjuncture, this equipment will provide a pressure reduction thermodynamic process for gas pressure reduction stations in gas transmission pipelines that does not require the supply of external energy for re heating, with the associated cost and pollution and on top of it, recovers in the form of electrical energy part of the elastic energy lost by the gas.
It is also significant the application of this equipment in gas liquefaction plants, since it will achieve the desired results with lesser energy consumption.
Enhanced Oil Recovery Pilot Testing Best Practices
Authors: Teletzke G. F. , Wattenbarger R. C. , Wilkinson J. R. 
Published: June 2009

Abstract
Enhanced oil recovery (EOR) implementation is complex and successful applications need to be tailored to each specific reservoir. Therefore, a systematic, staged evaluation and development process is required to screen, evaluate, pilot test, and apply EOR processes for particular applications. Pilot testing can play a key role in this process. Prior to field testing, pilot objectives need to be clearly defined and well spacing, pattern configuration, and injectant volumes determined.
This paper outlines a staged approach to EOR development and focuses specifically on pilot testing best practices. These best practices were derived from ExxonMobil's extensive piloting experience, which includes over 50 field pilot tests covering the full range of enhanced oil recovery processes. Topics covered include: 1) determining whether a pilot is needed and defining pilot objectives, 2) considerations for successful pilot design, 3) types of pilots and their advantages and disadvantages, 4) tools and techniques for assessment of key reservoir mechanisms, and 5) minimizing uncertainty in pilot interpretation. Key issues that are often addressed by pilots are discussed, including areal sweep and conformance, gravity override, viscous fingering, and loss of mobility control. Also included are aspects of instrumentation and measurements in pilot injection, production, and monitoring wells. Several ExxonMobil piloting examples are used to illustrate the best practices, including a single-well injectivity test, an unconfined pilot with observation wells, a small-scale confined pilot, and a large-scale multi-pattern pilot.
Utilizing Online Water Detection to Automate Production Management
Authors: Mohajer Kam 
Published: June 2009

Abstract
In today's competitive energy market there is a tremendous emphasis on cost saving and productivity at all levels of the industry. Online water detection provides vital real-time information regarding water concentrations in hydrocarbons with numerous beneficial applications. Specifically, with the high volume of produced water in today's wells, utilizing oil water detectors or OWD's to automate production management creates efficiencies in terms of time, cost and vital man hours, and OWD's incorporating microwave technology demonstrate extreme accuracy even at the highest water concentrations.
Currently, production is manually managed by the rotation of "producing" and "shut-in" wells. This system creates a great deal of waste and cost both in terms of produced water and energy utilized. The installation of OWD's on each well creates a continuous flow of data specific to each well that can be combined with separation and flow data, then sent to a remote dashboard for monitoring.
Utilizing such a system gives the production operations team the real-time, site-specific data required to automate and maximize efficiencies throughout the production process. In particular, it provides the knowledge required to shut-in wells with high water production levels and concentrate production on those wells currently producing higher concentrations/volumes of oil and to do so on an as-needed basis. What's more, this process can be informed and enhanced by a wide variety of criteria specific to your needs such as oil-water separation capacity, water-disposal capacity, flow rates, etc.
The efficiencies created in production management are particularly vital in today's production climate where current levels of demand increase the pressure and importance of every producing well. At the same time, these wells are producing record amounts of water. Higher produced water concentrations combined with increased demand create an imperative for maximizing both the efficiency and automation of production.
Facies Modeling Using Multiple-Point Statistics: An Example from a Carbonate Reservoir Section Located in a Small Part of a Large Shelf Margin of Arabian Gulf, UAE
Authors: Arslan Izzet , Ribeiro Maria Teresa , Neaimi Mohamed Al , Hendrawan Irfan 
Published: June 2009

Abstract
A new breakthrough in reservoir modeling is using Training Images (TI) with Multiple Point Statistics (MPS). A TI is a structural image of a reservoir layer or stratigraphic time interval, which represents all the relevant events (e.g. facies) at a time independently from a real location. Therefore, the Tl's capsulate much broad geological sense with conceptual patterns or multiple joint relations beyond the traditional geostatistics where it may merely offer two-point correlations (e.g. variograms) with sparse well data.
Each time sequence presents a transgression within Arabian plate along hundreds of km's distance length one would not see the whole sequence of a platform (e.g. lagoon, ramp and shoal deposits) through a relatively small reservoir area (30km × 30 km). This brings a common challenge in facies modeling of carbonate reservoirs regarding lateral changes in deposition settings that are rarely crossed along the small scale reservoir sequences although a diversity of facies types can be observed vertically.
The Arabian Gulf plate reservoir of Lower Thamama around Abu Dhabi was studied to understand how a relatively limited reservoir area was deposited through the help of Tl's. A rock-type study based on core and log data was compiled, and 23 facies types varying vertically were identified. Tl's were drawn for each time interval between high resolution sequence stratigraphy (HRSS) picks. It was not eligible to drive properties through seismic attributes since the seismic attributes were weak for tuning the facies heterogeneity. The analogs, representing the depositional strata sketch were mapped with outcrop data, core descriptions and solid geological knowledge of the reservoir. Given these conceptual images conditionally, all possible scenarios of the deposition were simulated with MPS algorithms. Uncertainty analysis was also performed to infer the variability of the different TI's.
Improving Lifecycle Project Delivery Through Better Decision-Making Under Uncertainty
Authors: Yawanarajah Shareen , Williams Jevon , Carrell Ken , Webb Tom , Cox Mike 
Published: June 2009

Abstract
The total value realized from an asset depends on how well it is managed throughout its lifecycle, from exploration to early development to abandonment. Decisions in all phases of field life cycle depend on the proper use of uncertain information. Shortcomings in uncertainty management are primarily a problem of organizing work processes, providing access to consistent information, and managing projects across organizational boundaries. A key critical success factor is also strong inter-disciplinary decision-making in all decision domains.
Recognising this, in Shell, within the development-planning phase of the field life cycle, we have developed two key programmes for New Projects that integrate decision-making under uncertainty with technologies to mitigate risks, and skills and workflows to implement them.
In the first programme, we streamline the activities involved in planning the field development. This includes simplifying project management responsibilities, managing subsurface uncertainties more effectively and enabling work to be done more collaboratively. Using a tool that was co-developed with Schlumberger, we have been able to make visible to the key stakeholders/decision-makers fit for purpose work plans, track milestones and action items, as well as capture "as-is" thinking, work-in-progress data/documents and team decisions throughout the life cycle.
In the second programme, we have developed a company-wide methodology that brings Smart Fields elements into project design planning. It identifies the most appropriate technologies to mitigate operational risks and enables their application. The methodology, referred to as Smart Fields Initial Screening, uses a structured process to match the appropriate Smart Fields integrated solutions to the specific needs of the project. This is done for all key components of the production system.
The new ways of working are enabled by bringing together -- in one room or virtually -- skilled people for multi-disciplinary discussions to jointly interpret the information to make fast, good decisions to improve project delivery and enable better field performance.
Neural Net Prediction of Porosity From Seismic Successfully Used to Improve the Reservoir Model Away From Well Control
Authors: Zaabi N. Al , Soroka W. L. , Abousetta A. A. , Kaya A. S. 
Published: June 2009

Abstract
To maximize recovery from carbonate reservoirs it is necessary to build models that include as much detail as possible about the variations in reservoir properties. Due to the heterogeneous nature of many carbonate rocks the standard techniques of building a porosity model by using well data alone can produce models that do not accurately represent the true subsurface geology. Seismic data is another source of information that can provide valuable details about the changes in porosity away from well control. An inversion was performed on a seismic volume over an Abu Dhabi field to generate an acoustic impedance model of the reservoir. Using the acoustic impedance, available well data and other seismic attributes a neural net project was performed to produce a porosity volume. The porosity volume was in agreement with porosity log data at the well locations and showed lateral porosity variations that could be used to update the porosity in the reservoir model. A porosity volume was also calculated from the inversion acoustic impedance results using a porosity to acoustic impedance relationship derived from the log data. The inversion porosity model was used as and additional control on the neural net porosity from seismic results and for validation.
The porosity from the neural net project was transferred to the reservoir model building software and successfully used to validate and update the porosity in the reservoir model away from well control. The revised porosity model more accurately showed the affects of faults on porosity and porosity changes due to digenesis and facies changes. The added details and more accurate lateral variations in reservoir porosity obtained from seismic information has the potential to produce more accurate and reliable simulation models showing the dynamic behavior of the reservoir.
Geosteering Optimization in Thin Carbonate Reservoirs
Authors: Ramos L. , Ali S. , Maskary S. Al , Abou-Mostafa S. , Mirto E. , Padiav P. , Aki A. 
Published: June 2009

Abstract
Targeting more complex and challenging reservoirs in terms of stratigraphy and structure, makes improved geosteering precision a necessity. This is particularly true when targeting thin permeability streaks or avoiding thin dense layers in highly heterogeneous reservoirs. The challenges are even greater when these thin reservoirs are highly faulted and the risk of missing the target is higher. Applying a proactive approach for well trajectory optimization while drilling and using the most recent logging while drilling (LWD) technology such as distance to boundary measurements, real-time image logs integrated with other LWD logs and 3D structural/properties models, it is possible to maximize the wells value. Deployment of these new technologies allows tracking the "sweet spots" of the reservoir more efficiently as uncertainties related to the dip, thickness of the reservoir and fault/fracture occurrence are better managed. This approach saves time and money by reducing the chances of missing reservoir targets and therefore the need to sidetrack or drill a complete new well. Another benefit from these procedures is the well accessibility which is highly improved due to an increased in the borehole smoothness, which is achieved through better control of the well trajectory. In this paper, several examples will be shown for different scenarios in different oil fields/reservoirs in Abu Dhabi, U.A.E.