bluuebunny/crossref_metadata_2025_split huggingface dataset:
An Innovative Manganese Tetra-Oxide/KCl Water-Based Drill-in Fluids for HT/HP Wells
Authors: Al-Yami A. S. , Nasr-El-Din H. A. , Al-Majed A. A. , Menouar H. 
Published: December 2007

Abstract
Drilling Unayzah-B gas reservoir (shale and sandstone) in Saudi Arabia requires high mud density (± 95 pcf). To formulate this mud, calcium carbonate particles were used, because of their high acid solubility. However, when drilling the 5-7/8 inch hole, sticking occurred, which resulted in expensive fishing and/or sidetrack operations. To minimize these problems, barite was added with CaCO3 to reduce the amount of solids needed to formulate the drill-in fluid. However, barite is acid in-soluble and may cause formation damage. Formate drill-in fluids with low CaCO3 content were used to drill some wells in this reservoir, however these fluids are expensive and corrosive if their high pH values were not maintained in the field.
Saudi Aramco has developed drill-in fluids that are based on manganese tetra oxide particles to drill deep gas reservoirs. The properties of these (D50 = 1 micron), spherical shape, and high specific gravity (4.8 g/cm3) make them good weighting material compared to CaCO3 (2.78 g/cm3 and D50 = 10 micron) and BaSO4 (4.25 g/cm3 and D50 = 20 micron).
The main objective of this study is to discuss lab work that was performed to design water-based drill-in fluids using KCl/Mn3O4 at 95 pcf. A second objective is to compare the properties of the new fluid with two typical fluids that are currently used to drill Unayzah-B reservoir. The first fluid is KCl/BaSO4/CaCO3 and the second one is potassium formate/CaCO3. The experimental work included measuring the rheological properties, thermal stability, API and HT/HP filtration of the three drill-in fluids.
The results obtained showed that several polymers can be used to design KCl/Mn3O4 –drill-in fluids. The developed fluid had better thermal stability and filtration control compared to the drilling fluids that are currently used. This paper will discuss the results obtained and will demonstrate that the new fluid can save time and cost of drilling deep wells.
Network Approach for Optimization and Control of Intelligent Well Systems: Theory and Practice
Authors: Ajayi Arashi , Konopczynski Michael , Sukkestad Tor 
Published: December 2007

Abstract
Intelligent well systems are gradually gaining ground in the development of hydrocarbon assets. One of the reasons is the value added by the technology in maximizing production relative to conventional systems because of its flexibility in reacting to detrimental production conditions.
The maximization benefit is closely tied to a simple, consistent, robust and standardized optimization process. This paper describes a network optimization and control methodology that can be implemented in either a zonal compensation or distribution mode. In a compensation mode, the technique maximizes total well throughput of a specified fluid stream (oil or gas) in a multi-zone commingled intelligent well system by rewarding favorable zones and penalizing unfavorable ones. In zonal distribution mode, it is used to allocate rates to contributing zones based on predefined distribution factors.
The approach is similar to those used in resource allocation and dynamic programming. Unlike the gradient-based method, this approach does not require calculations of differentials. Instead, it uses historical zonal production, pressure/temperature data, and installed down-hole component properties to recommend new operating conditions for each zonal down-hole interval control valve (ICV). The analysis involves characterization of the zonal ICVs within the boundaries of the contributing reservoirs and specifying dynamic or static constraints for the well of interest. This analysis is then combined with existing zonal and total well data to predict an optimized operating condition for the zonal ICVs. The method can be used both in a reactive or proactive mode. It can also be used in a discrete or continuous flow process. The paper discusses the optimization and control process and provides two field cases.
Eliminating Buoyant Migration of Sequestered CO2 Through Surface Dissolution: Implementation Costs and Technical Challenges
Authors: Burton McMillan , Bryant Steven L. 
Published: December 2007

Abstract
Sequestration of CO2 in geologic formations will be part of any substantive campaign to mitigate greenhouse gas emissions. The risk of leakage from the target formation must be weighed against economic feasibilities for this technology to gain stakeholder acceptance. The standard approach to large-scale geologic sequestration assumes that CO2 will be injected as a bulk phase into a saline aquifer. In this case, the primary driver for leakage is the buoyancy of CO2 under typical deep reservoir conditions (depths &gt; 2600 ft or 800 m). Investigating alternative approaches that utilize inherently safe trapping mechanisms can help to characterize the price of reducing the risk of leakage.
In this paper, we investigate a process in which CO2 is dissolved in brine prior to injection into deep subsurface formations. The CO2-laden brine is slightly denser than brine containing no CO2, so ensuring the complete dissolution of all CO2 into brine at the surface prior to injection will eliminate the risk of buoyancy-driven leakage. We examine the feasibility of dissolving CO2 at surface facilities and injection of the saturated brine. To estimate the costs of this process, we determine the capital costs for the additional facilities and compare them the capital costs for injecting bulk phase CO2. We also estimate the power requirements to determine the additional operating costs. The additional capital and operating costs can be regarded as the price of this form of risk reduction.
Comparing this alternative to the standard, we find that an additional power consumption of 3% to 8% of the power plant capacity will be required and the capital costs will increase by 34% to 44%. Brine is required at rates of millions of barrels per day, and in most applications this would be lifted from the target aquifer. The bulk volume of the aquifer is on the order of a hundred million acre-ft for reasonable power plant sizes (250MW to 1000MW) and for reasonable injection periods (30–50 years). Although this alternative results in higher costs, surface dissolution may be attractive where the costs of monitoring or insuring against buoyancy-driven CO2 leakage exceed these additional costs.
Improved Production and Process Optimization Through People, Technology, and Process
Authors: Sagli Jan Richard , Klumpen Hans Eric , Nunez Gustavo , Nielsen Frank 
Published: December 2007

Abstract
A joint venture Production & Process Optimization project between Statoil and Schlumberger is targeting two distinct areas: ■Improved reservoir management to optimize the reservoir performance over the life of the field.■Production optimization of the intelligent wells, production network and process facilities on a day-to-day basis. This is achieved through development of tools, methodologies and workflows.
In order to support the change management process, a prototyping process has been developed for surveillance workflow development and deployment. The dynamic prototyping process allows a bottom-up development of workflows starting from data conditioning and reconciliation up to optimization and control. These different automation modes for provided workflows go along with deriving information and ultimately knowledge from production process data in order to improve decision making processes.
A demonstration project will concentrate primarily on the Water Alternate Gas (WAG) cycle optimization process, which has been specified together with the asset team, and will describe how the workflow supports production optimization.
The solutions are successively tested together with the Snorre B asset. Results from the demonstrator, change management issues and the concept of full integration of all decision making loops into a workflow framework will be presented in the paper. During the testing not only the application of the software solution was evaluated as well the impact on the organization and how changes in proposed work processes improved the inter domain collaboration within the team.
The project has demonstrated successfully that three key areas have to be addressed simultaneous: ■Change Management procedures in order to introduce the developed workflows and software tools as early as possible■Necessary software tools for providing a workflow oriented framework for production optimization■Prototyping workflows and implementation through demonstration and pilot projects as well as permanent facilitators working with asset teams
Where Will the Next Generation of Petroleum Engineers Come From? Disturbing Observations From a Texas Oil Town
Authors: Schrader S. M. , Balch R. S. , Bunnell D. 
Published: December 2007

Abstract
There is a concern in the oil and gas industry about an imminent shortage of professionals. Many factors contribute to this expected staff shortage, including large numbers of oil workers nearing retirement age, worker diasporas during lean times, lack of job prospects for students during the 80's and 90's and the resulting decline in enrollment in petroleum engineering programs. Currently, the industry is recruiting aggressively, offering high salaries; many college students have jobs arranged by their junior year. It might be expected that students would be enticed to prepare for careers in the oil and gas industry, especially in areas like west Texas, where the oil industry contributes enormously to the economy, oil jobs are plentiful, and are salaries high. However, a discussion with college bound juniors and seniors at Odessa High School in west Texas revealed that very few intended to pursue oil and gas-related careers. This disturbing result led to the authors to develop a survey to evaluate high school students for their interests in, and attitudes about, the industry.
Survey questions cover the students' overall view of the industry, their impressions of industry technology, their desire to work in industry, factors affecting that desire, and general demographic data
Initial observations indicate that students believe the oil and gas industry is low-tech, jobs are highly paid but unreliable, oil and gas will not be major energy resources in the future, and that a high school education can earn an employee close to what degreed employees earns, diminishing the value of a petroleum degree.
Workover Successes in Deviated Wells Using Multispinner Production Log Data
Authors: Horner Steve , Grayson Steve , Elliot Burt , Sandoval Alex , Alban Patricio 
Published: December 2007

Abstract
This paper gives the details and results of a successful workover program conducted offshore California in 2006. The wells are highly deviated, producing oil, gas, and water from natural fractures. Analysis from a new production-logging tool, coupled with geologic data and a new artificial lift system design, were used to optimize production.
The new production logging tool uses multiple probes to characterize complex flow profiles and quantify fluid entries in horizontal and deviated wells. Tractor conveyance while logging was required on one of the wells. Previous workovers in the area, using older technology log data, had shown variable results. More aggressive water control techniques were employed in one well, where a fault intersection caused a major water influx in the middle of the perforated section. The water productive intervals were squeezed and the surrounding oil zones re-perforated and stimulated, resulting in decreased water and a 12-fold increase in oil production. In another well, analysis indicated that a bottom-water shutoff and conversion to an electrical submersible pump would optimize this high-productivity index well. The results confirmed this, however the gas/liquid ratio increased and the pump began to gas lock, causing the well to produce below its maximum potential. Using the production log data, engineers landed the pump below the main gas producing zone to allow gas to vent directly up the casing. A redesigned ESP with the new helicoaxial gas handling pump and downhole sensor were utilized to optimize bottomhole flowing pressure and increase oil production by more than 200 BOPD.
Pasting the production logs along the well trajectories in our 3D geological model led to interesting conclusions about the sources of water production. Excessive water production correlated with perforated zones located at the intersections with fault surfaces. This graphical technique could be used by other operators of fractured reservoirs.
Evidence of a Horizontal Hydraulic Fracture at Depth Due to Stress Rotations Across a Thrust Fault
Authors: Maxwell S. C. , Zimmer U. , Gusek R. , Quirk D. 
Published: December 2007

Abstract
Microseismic imaging of a hydraulic fracture stimulation showed significant fracture reorientation across a thrust fault. Fracture orientations were identified through a combination of alignment of event locations, polarization of the seismic waves and injection details. Stimulation below the fault indicated a near horizontal fracture geometry. Above the fault, a near vertical fracture geometry was observed. A change in fault orientation was supported by differences in the microseismic signal characteristics and the treatment injection data. This difference in fracture geometry was attributed to rotations in the direction of minimum principle stress, which is consistent with observed differences in the injection pressures. The fracture reorientation suggests a significant difference in the stimulated permeable pathways for sands above, compared to below the fault.
Introducing New API/ISO Procedures for Proppant Testing
Authors: Kaufman Phillip B. , Brannon Harold D. , Anderson Robert W. , Ziegler Mark , Neves Aidner R. , Parker Mark A. , Abney Kathy , Cortes Gabriel Warwick Kerr de Paiva , Joyce Sara , Penny Glenn S. 
Published: December 2007

Abstract
In 2001, the International Organization for Standardization (ISO) and American Petroleum Institute (API) formed a new committee to write procedures for measuring the properties of proppants used in hydraulic fracturing. API Recommended Practices (RP) for testing of proppants are generally "reviewed and revised, reaffirmed, or withdrawn at least every five years" in accordance to API instructions. The last Recommended Practice was published in December 1995. The committee was charged with re-writing API RP 56, 58, and 60 relating to sand as a proppant, gravel packing, and high strength proppants, respectively. This new document, ISO 13503-2 "Measurement of Properties of Proppants Used in Hydraulic Fracturing and Gravel-Packing Operations" is a standard. Any company may follow these procedures and state on their published data that they followed ISO procedures to generate the specifications of their product. Several changes have been made to the Recommended Practices, and the goal of this paper will be to highlight these changes, and to discuss the potential impact on the proppant industry. In 2003 a second committee was formed to write procedures on measuring long term conductivity of a proppant pack. The industry was using for years a procedure based on API RP 61 "Recommended Practices for Evaluating Short Term Proppant Pack Conductivity" 1989, which is an obsolete document. Roughly a dozen facilities worldwide are running long term conductivity tests, all slightly different. Recent advances in technology have been incorporated in this standard to increase the accuracy of the results, and to standardize the equipment and testing procedures. The new standard is ISO 13503-5 "Procedures for Measuring the Long-Term Conductivity of Proppants".
These two new procedures will enable users to evaluate and to compare proppant characteristics under the specifically described test conditions for use in hydraulic fracturing operations. They are not designed to provide absolute values of proppant conductivity under downhole reservoir conditions. Test data has shown that time, elevated temperatures, fracturing fluid residues, cyclic stress loading, embedment, formation fines, and other factors will further reduce proppant pack conductivity.
Real-Time Diversion Quantification and Optimization Using DTS
Authors: Glasbergen Gerard , Gualtieri Dan , Trehan Rakesh , Van Domelen Mary , Nelson Micky 
Published: December 2007

Abstract
In matrix treatments, optimum placement of the injected fluids is essential. Over the years, several diversion techniques have been applied to obtain a desired fluid distribution. The latest developments in the application of distributed temperature sensing (DTS) during matrix treatments to monitor temperature profiles along the wellbore in real time show that fluid distribution can be quantified.
This paper discusses the application of DTS to quantify the effectiveness of diversion agents. Quantification of fluid distribution makes it possible to determine the flow distribution both before and after a diverter stage so that the diversion effect can be evaluated.
Knowledge of the diverter effect will lead to better understanding of the diversion process and subsequently to optimization of future treatment designs. Ultimately, use of real-time quantification of the effect of diversion will lead to the development of real-time optimization itself. In real-time optimization, the results of a diverter stage will be used to adjust the next diverter stage to optimize placement.
The post-treatment analysis of the temperature profiles showed that flow distribution can be quantified both before and after a diverter stage. Based on the observations, the decision was made to develop a diagnostics tool that can be used in real time and will enable real-time quantification.
The novel approach of using the diagnostics tool in combination with DTS during matrix acid treatments will help to further optimize diversion treatments. This optimization is both an optimization during the treatment and an optimization of diverter stages in future treatments.
On IFT Measurements to Estimate Minimum Miscibility Pressures
Authors: Jessen Kristian , Orr Franklin M. 
Published: December 2007

Abstract
Measurements of the interfacial tension of mixtures of a reservoir fluid and injection gas at various pressures have been proposed as an experimental method for predicting the minimum miscibility pressure (MMP) in an experiment called the vanishing interfacial tension (VIT) technique. In this paper we analyze the accuracy and reliability of the VIT approach based on phase equilibrium and slimtube experimental observations and equation of state calculations of the behavior of VIT experiments for the same systems.
We consider 13 gas-oil systems for which phase equilibrium and density data and slimtube measurements of the MMP are available. We show that tuned equation of state characterizations using 15-components to represent the gas/oil systems yield calculations of phase compositions and densities and calculated MMPs that reproduce accurately the experimental observations. We assume that IFTs can be calculated with a parachor expression, and we simulate the behavior of a series of VIT experiments with different mixture compositions in the VIT cell. We show that compositions of mixtures created in the VIT cell are not, in general, critical mixtures and that calculated estimates of the MMP obtained by the VIT approach depend strongly on the composition of the mixture used in the experiment. We show also that those MMP estimates may or may not differ significantly from values obtained in slimtube displacements. Fortuitously chosen mixture compositions can result in VIT estimates that agree well with slimtube MMPs, while for other mixtures, the error of the estimates can be quite large. In particular, we show that errors in the VIT estimate of the MMP are often large for gas/oil systems for which the first contact miscibility pressure is much larger than the slimtube MMP.
We conclude, therefore, that the VIT experiment is not a reliable single source of information regarding development of multicontact miscibility in multicomponent gas/oil displacements.
New Remote Collaboration Models for Oil and Gas
Authors: Matson J R , Krome J D , Chmela W 
Published: December 2007

Abstract
The Intelligent Oilfield (IOF), also known as the Digital Oilfield of the Future (DOFF), encompasses a collaborative environment (CEs) for communication, data collection, reporting and monitoring, and knowledge & information sharing. These environments, or physical workspaces, are intended to help people make more informed decisions and to take the appropriate actions across the enterprise. In addition, it enables alignment, focus, and a common understanding to help prioritize opportunities.
Innovations in various collaboration technologies are helping companies to make the intelligent oilfield a reality. One of the key implementation components currently attracting attention is the collaboration or remote surveillance center – a high-tech, communications, visualization, and audio-enhanced monitoring or control room. Although the facility is intended to create an atmosphere for improved communications, multifunctional work, and a means to help eliminate organizational barriers, the center itself is only the physical manifestation of the desired spirit of richer and increased human interaction.
There are currently two differing philosophies for the implementation of these centers – an asset-based center that services a single asset and a central hub that services multiple assets. Each approach has its own particular merits and potential pitfalls. Although there is no single right answer, certain considerations are recommended before construction begins that could assist in determining the most appropriate approach for the given circumstances. Factors such as corporate culture and employee skill base can have a huge impact on the success of the final choice. Without such an evaluation, many efforts will continue to be burdened or opportunities will be deferred or lost.