bluuebunny/crossref_metadata_2025_split huggingface dataset:
The Economics of Compressed Natural Gas Sea Transport
Authors: Marongiu-Porcu Matteo , Wang Xiuli , Economides Michael J. 
Published: October 2008

Abstract
Natural gas has come to the forefront of the international energy debate. The reasons include increasing demand in the United States, China and India and a changing worldwide preference in power generation because of environmental concerns. As a result, the transport of natural gas becomes important. Currently, 70 percent of gas is transported to market by pipeline and 30 percent as liquefied natural gas (LNG).
Pipelines are attractive but, offshore, their feasibility is greatly hindered by distance limits and terrain restrictions. On the other hand LNG facilities are expensive to construct and the process is complicated, costly and energy wasteful. It is applicable primarily for long distances and large volumes of gas.
Sea-going compressed natural gas (CNG) is an alternative that has been proposed in recent years but has not made substantial headway for two reasons: 1) the emphasis for investments by producers and large consumers has been primarily on LNG; 2) CNG boat designs and projects have been envisioned to eke a bite out of the LNG pie which is not necessarily a good approach.
CNG must make a niche in smaller markets and shorter distances. Here we present definitive economics by performing a specific case study for Sakhalin Island, Russia. Results delineate the landscape where this mode of transport is attractive and how it can be deployed with specific requirements of distance, market size and size distribution. Our studies show that for shorter distances (e.g., 500 km, about 300 miles) and even relatively large volumes, LNG cannot compete with CNG and at longer distances (e.g., 2,000 km, about 1,250 miles) CNG is far more attractive at small volumes, assuming that offshore pipelines are not feasible. For volumes such as 1 to 2 billion cubic meters per year (about 35 to 70 billion cubic feet per year), CNG is the only feasible solution to bring this energy source to many markets. These findings suggest that many parts of the world (such as the entire Mediterranean basin, the Scandinavian peninsula, Sakhalin Island, South-East Asia and the Caribbean) would be better served by CNG even if LNG projects have already been approved and under construction.
We also performed a sensitivity study on gas price (both at the source and at the market) impacts on the value of both CNG and LNG projects and determine the breakeven points under a given gas demand of e.g., 1.5 Bcm/yr (about 50 Bcf/yr) and a distance of 1,500 km (about 900 miles). For example if the source price is $6/MMBtu then the breakeven price for CNG is $10.05 whereas for LNG it will have to be $14.24, a 40% increase.
Well-Test Interpretation with Behind-the-Casing Crossflows
Authors: Kremenetskiy M. I. , Kokurina V. V 
Published: October 2008

Abstract
This study considers the potential use of well-testing for investigating cross-flows in production wells.
Using a numerical model, the authors detected pressure behavior patterns which may become informative characteristics for diagnosing a cross-flow. To increase diagnostic reliability, the optimization of measurement technologies and interpretation methods to manage pressure behavior pattern characteristics are substantiated. These testing techniques make it possible to distinguish behind-the-casing fluid movement where background interference is present.
One of the most interesting areas of application of the results obtained in this study is monitoring unsteady fracture creation in injection wells. Such fractures occur when the injection pressure exceeds reservoir fracturing pressure, and they break down shale layers between formations. When pressure is reduced, the fractures close up, and cross-flow stops. That is why the derivative behavior during the injection cycle significantly differs from that of the static state.
Numerous examples illustrate that well testing is considerably more successful when combined with downhole logging.
A Milestone for Smart MRC Wells in Saudi Arabia
Authors: Al-Umran Mohammed I. , Al-Shenqiti Mohammad S. , Zhou Shaohua , Al-Nasif Mohammad A. 
Published: October 2008

Abstract
Smart completions in maximum reservoir contact (MRC) wells have played a critical role in advanced reservoir management and production optimization in Saudi Aramco. Smart MRC wells are mostly completed along the motherbore in cased holes, and occasionally in open holes. The main smart completion equipment consists of hydraulically-controlled interval control valves (ICVs), isolation packers with feed-through control lines, and permanent downhole monitoring systems (PDHMS).
Due to the complexity of smart MRC well drilling and completion, it sometimes becomes necessary to have the option to retrieve the completion equipment. Examples of these situations include downhole equipment failure during the completion process, or less than optimal or poor wellbore placement. Previous field experiences show that it can be difficult – or at least challenging – to de-complete a smart MRC well.
This paper will present a technical milestone achieved in a workover operation in November 2007. Recently, Saudi Aramco decided to workover a smart MRC well first completed in July 2005, due to poor lateral placement. After the de-completion, the plan was to sidetrack the well to regain oil production. This paper will also discuss the planning and operational steps that led to a successful three-day rig time involved with a coiled tubing (CT) operation to shift sleeves and unset packers. This resulted in the first time that smart equipment had been completely retrieved without a problem. That successful de-completion paves the way for further workover requirements of smart MRC wells, if needed. This paper will also summarize key equipment requirements and lessons learned in order to achieve successful de-completion of smart MRC wells.
Application of Brown-Field Experimental Design Techniques to a Super Giant Carbonate Reservoir
Authors: Billiter Travis C. , Dagistanova Kymbat , King Greg R. 
Published: October 2008

Abstract
Brown-field experimental design techniques were applied to the Tengiz super-giant carbonate reservoir. This brown-field study combined experimental design, reservoir simulation, and available historical pressure and production data to develop proxies to predict the history match quality and oil recovery of equally probable reservoir realizations. The authors used experimental design techniques similar to those documented in Landa et. al.1 and King et al.2; however, the effort documented in this paper incorporated a much larger brown-field component and highly non-linear response surfaces required many more runs (control points) to generate reliable proxies.
The initial simulations runs included a folded Plackett-Burman design with a centerpoint run and sensitivity analysis runs which varied the input parameters that were known to affect the history match. The results from these runs were analyzed using regression analysis and ANOVA techniques to determine the most significant factors and to understand the complexity of the response surfaces. With this knowledge, D-optimal runs were designed and run to better understand the effect of the interaction of the significant factors on the response surfaces. Additional sensitivity analysis runs were also made to further define the effect of the two most important factors on the response surfaces: OOIP and reservoir transmissibility. With a total of 107 unique runs, the authors were able to develop five proxies to assess history match quality and one proxy to predict oil recovery.
With the developed proxies, the authors used Monte Carlo techniques to generate equally probable reservoir/development scenarios. By using the history match quality proxies the authors were able to filter out combinations of subsurface parameters that caused unacceptable deterioration in the history match. The use of the five unique filters allowed the authors to significantly reduce uncertainty relative to the unfiltered simulation results. The results from this work were supported by material balance studies.
Well Productivity and Oil Recovery Enhancement in East and West Siberian Fields as a Result of Inflow Control Technology and Application
Authors: Kudryashov Sergey , Zaikin Igor , Kempf Konstantin , Voll Benn , Budlov Sergey , Laidlaw Duncan 
Published: October 2008

Abstract
A major Russian operator ROSNEFT has encountered operational risks and challenges in oil production due to the highly diverse reservoir properties of Siberian fields. The majority of the operator's east and west Siberian fields include heterogeneous sandstones with low to high permeability, complicated geological and stratigraphic cross-sections and an active bottom water aquifer. In some areas, a gas cap is one of the drive mechanisms.
Horizontal wells tend to become more popular in both green and brown fields because of improved recovery efficiency due to increased reservoir drainage area. However, unbalanced inflow profiles along horizontal sections can result in early water/gas breakthrough which shortens well life and decreases overall profitability.
This paper will describe the application of inflow control technology in two Siberian fields, addressing early water and gas breakthrough caused by intensive water injection and a massive gas cap, as well as sand control issue. Production is optimized by ensuring uniform inflow profile along lateral sections and minimizing annular flow. The setting selection process for inflow control devices is detailed. The resulting delay of water/gas breakthrough and increased longevity in these horizontal wells lead to enhanced recovery efficiency and improved productivity.
Watercut versus Oil Displacement - Main Reasons of Different Behavior
Authors: Ivanova Irina S. 
Published: October 2008

Abstract
Most of oil fields are developed on waterflooding. In some regions there are many fields with strong water drive. In both cases oil production is accompanied by water production.
From economical point of view income is proportional to oil production but operating expenses are proportional to liquid production. So, excessive water production can decrease profitability of a project. In some economical software there is a dependency of watercut upon oil displacement. But in reality foregoing dependencies are drastically different from field to field. This paper is devoted to finding regularities and confirmation them by means of analytical and numerical calculations.
Several influencing parameters are considered – such as relative permeabilities, fluid viscosities, fluid densities, heterogeneity and permeability profile, permeability anisotropy, layer slope, fractures, aqufer size and activity, well distance and patterns, position of perforation intervals, pressure drawdown, maximum allowed watercut. Those factors could be divided into two global groups – geological and technological.
Ultimate fraction of mobile oil displaced (volume sweep efficiency) depends on many factors. That is why field ultimate recovery factor is always less then laboratory displacement factor. But even laboratory waterflooding experiments show wide range of watercut vs. sweep dependencies for core samples from the same field. For the same maximum watercut (e.g. 98%) we can get from 0.6 to 0.9 sweep.
The quantity of water produced per unit of produced oil depends both on geology and technology. It's impossible to change geological environment but we can chose a proper method to develop any field. Field examples and practical recommendations are presented in the paper.
Setting the Standard for Resin Coated Proppant Testing
Authors: Barmatov Evgeny , Abbott Jonathan , Golovin Alexander , Burukhin Alexander , Kalinin Sergey , Straz Evgenia , Usova Zinaida 
Published: October 2008

Abstract
This paper describes the performance evaluation of curable resin coated proppants currently used in Russian Oilfields. The performance of these RCPs is compared based on established API/ISO standards and standard resin coated proppant testing methods currently applied within Schlumberger. These methods investigate further fluid compatibility between fluid systems and resin, proppant pack integrity under a variety and combination of curing conditions and proppant pack integrity under well flowing conditions. In the paper we evaluate the material performance of resin coated proppants used in Russia, showcase new resin coated proppant testing methods and demonstrate the need for firm industry standards devoted to the testing of resin coated proppants.
Experimental Design Reduces Risks of a Siberian Development with Subsurface and Financial Uncertainties
Authors: Tipping David E. , Deimbacher Franz X. , Kovyazin Dmitry , Medvedev Alexey , Valencia Randy 
Published: October 2008

Abstract
We applied Experimental Design methodologies to evaluate development options in a Siberian field with major uncertainties in the geological, reservoir and financial parameters. Our approach, used for the first time in Russia, demonstrates an inverted 7-spot injection pattern is expected to yield 11% more oil than a line drive – identified by conventional evaluation methods. Of more significance, for decision making, the analysis predicts that the expected net present value (NPV) of this pattern is 46% more than the pattern proposed previously.
The primary reservoirs consist of stacked fluvial, delta distributary channel and mouth bar sands. Although exploration tests confirmed oil rates exceeding 120 tonne/day, the location and orientation of the individual sand bodies could not be mapped from existing seismic. Recognising this was a risk to project success, we developed an Experimental Design technique for quantifying the uncertainties in oil rate predictions. The major stages were:
Identification of the 20 geological and reservoir parameters that influence the simulation production forecasts. Examples include the dimensions of the sand bodies, residual oil saturation, facies distributions, amongst others. Determination which parameters have a major impact on oil rate predictions. In principle, this requires simulating all combinations of possible values for the 20 parameters. In practice, this is not realistic; hundreds of thousands of dynamic models would be needed. With the Plackett-Burman Experimental Design, we only needed 48 reservoir descriptions – each consistent with the available field data – to identify the 11 significant subsurface parameters. Creation of a second order polynomial equation that expressed the net present value (NPV) as a function of the 15 most significant reservoir and financial parameters. This equation, intended to reproduce the response of the dynamic simulator and the financial model, gave a probabilistic distribution of NPVs for each development pattern. For the 6 patterns under consideration, we created the equation with a Composite Face Centred Experimental Design technique. This required a total of 378 simulation cases. Results from these cases were obtained in 3 days with the use of parallel processing technology that allowed submitting multiple models simultaneously.
Our experience shows that Experimental Design techniques integrated with advanced computer technology can cut evaluation times from months to weeks. More importantly, they give unbiased probabilities of production profiles and NPV so that downside risks can be quantified.
Formation Testing and PVT Sampling in Low-Permeability, High-Pressure Gas Condensate Reservoirs by Example of Achimovskaya Formation of Urengoyskoe Field
Authors: Achourov Vladislav , Kaledin German I. , Kroell Erwin , Rymarenko Konstantin , Jennevin Christian 
Published: October 2008

Abstract
Formation and fluids evaluation of heterogeneous and over pressured retrograde gas condensate low-permeability but high-reserves potential reservoirs requires use of advanced formation evaluation techniques. The Achimovskaya formation of Urengoiskoe field is one of Russia's giant low-permeability gas condensate fields. The main objectives of the pilot phase of the exploration projects in the Achimovskaya formation are reducing reservoir and fluid uncertainties, confirmation of technical and commercial feasibilities, construction of a pilot gas processing plant (UKPG), and startup of a pilot gas and condensate production. The initial formation evaluation in the first two "Achimgaz" vertical wells included an extended formation logging suite followed by formation testing and downhole PVT sampling achieved using a wireline formation tester (WFT) that had a dual packer to test a large area of open hole. Formation testing and sampling objectives were: reservoir evaluation, formation pressure profiling, direct measurements of mobility (effective permeability), downhole PVT sampling for hydrocarbons confirmation, and full laboratory studies of formation fluids before the production phase of the field. Rig time constraints were one of the main issues for the extended formation evaluation program, defining logging and testing scope.
In addition to traditional downhole sampling methods like low-shock PVT sampling (which allowed taking gas samples above the dewpoint), new approaches for logging and testing techniques were applied for the first time in Russia during this job. These were the combination of inflatable straddled dual packer wireline formation tester with nuclear magnetic resonance (NMR) logging in a single logging string and the use of two downhole pumps, also in a single string. The quality of sampling was controlled by application of downhole fluid analysis techniques. Comprehensive pre-job planning, close cooperation with drilling and operating companies’ representatives, and real-time decision-making during data acquisition led to the successful completion of the operation.
This paper describes this first successful application of a dual-packer wireline formation tester to obtain PVT samples of retrograde gas in the Achimovskaya formation. As a result of the job, the presence of hydrocarbons was proved, formation pressure and mobility profiles were obtained along the tested sublayers of Achimovskaya formations, and high-quality PVT fluid samples were acquired. This provided valuable information for future testing, appraisal drilling, and field development planning. Furthermore, comparison between core permeability, formation testing fluid mobilities, and NMR permeabilities acquired in one of the exploration wells is also shown in the paper.
Facilitating Data Quality Improvement in the Oil and Gas Sector
Authors: Radhay Rene 
Published: October 2008

Abstract
Seamless workflows among and within functional groups, and the resulting quality of inputs used for decision making, are common areas of concern in the oil and gas industry today. Sales of information management applications and methodologies are based on this definition of quality, which refers to the usefulness and direct availability when needed of known or high-quality information. The reality, however, is that increasing pressure to reduce costs, the volume and dynamic nature of E&P workflows, and the difficulty in measuring return on investment in addressing data quality have led to the existence of "siloed" workflows, databases of substandard quality, and resulting decision-making inefficiencies. These inefficiencies are frequently accepted as the nature of the job, both because of the difficulty in measuring their impact, and the challenge of effectively measuring the return on vestment that would result from improvements. One solution to this situation is to apply technologies and methodologies that have been proven in other industries. This can help determine key performance indicators - from operation to executive levels - to enhance workflow and data quality, and can also facilitate fast cleanup and the trending of improvements and their impact on the bottom line and user perception. Modular technology also facilitates phased rollouts to minimize investment before value can be determined. Business Process Management and Six Sigma methodologies, proven in other industries, can help control cross-functional processes and the systematic reduction of defects to acceptable levels, opening the door to the establishment of industry-relevant quality benchmarks that can ultimately impact investor confidence in the oil and gas sector and within individual organizations.

Introduction
Personal as well corporate experience with oil and gas data has revealed that data quality is a huge problem at many oil and gas companies. Based on this realization, this project's goal was to combine proven and well known technologies and methodologies to create an information management framework that would facilitate measurable improvements in oil and gas data quality. A recent survey showed that 49 percent of oil and gas companies would perform information management differently if starting over from scratch - justifying the need for a fresh approach. It can been seen that technology and methodology well proven in other industries can greatly assist in the oil and gas domain in improving and controlling data quality.
Successful Cementing Case Study in Tuscaloosa HPHT Well
Authors: Ravi Kris , Vargo Richard , Lasley Barbara 
Published: October 2008

Abstract
The wells in the Tuscaloosa trend in South Louisiana are high-pressure high-temperature (HPHT) wells reaching as deep as ±23,000 ft, with a bottomhole static temperature (BHST) as high as ±400°F. In the past these wells were completed using conventional cementing techniques. In some cases, soon after the wells were put on production, the intermediate casing annulus would show an increase in pressure. Historically, this pressure is manageable and can be easily reduced through current procedures and practices. However, a project was undertaken to understand the underlying cause and then subsequently deploy a solution to prevent pressure on the annulus side.
The first task was to make sure that the annulus pressure was not caused by other problems such as wellbore stability, hole cleaning, and cement slurry placement. Then the next possible cause was damage to the cement sheath during subsequent well operations and production. A detailed study was done to investigate this possibility. Mechanical and thermal properties of the formation were derived from the log data and drilling data. Additionally, this data was evaluated to identify the depths and formations associated with significant gas shows at surface.
Possible failure mechanisms in the previous conventional cement sheath were identified. The cement system was modified to prevent such failure and the new cement system was designed and tested. The modified cement system was deployed in the field in April 2006, and the well was put on production a few months later, and since then has been on line and producing without annular pressure problems.
The techniques and solutions discussed in this paper can be applied to wells around the globe that have related problems. These solutions may help prevent annular pressure and improve the safety and economics of operating these wells.