bluuebunny/crossref_metadata_2025_split huggingface dataset:
Case Study of Unconventional Gas-Well Fracturing in Hungary
Authors: Shaoul Josef R. , Spitzer Winston , Dahan Matthew W. 
Published: April 2012

Summary
Well Ba-E-1 was drilled in the Tompa prospect (now the Ba-IX Mining Plot) in Hungary targeting the Miocene and Cretaceous formations between 2600 and 3500 mTVD. These are tight sandstones, and the expected permeabilities were in the range of 0.001 to 0.5 md. Two hydraulic-fracture treatments were performed. The first fracture treatment was in the lower part, and the second treatment was in the upper part of the deepest interval. With no previous propped-fracturing experience in this field, the first treatment was designed as a conventional crosslinked-gel treatment to minimize the risk of a premature screenout. Following the analysis of the data from the first zone, it became clear that the average permeability was closer to the minimum expectation of 0.001 md. Because of lower-than-expected stimulation effectiveness of the first fracture, and the confirmation of the low permeability, the second fracture treatment was changed to a water-fracture design. This formation clearly falls into the unconventional category, and consequently was a good candidate for a water fracture.
This paper describes the prefracture diagnostics, fracture execution, and post-fracture production evaluation of this unconventional gas well. Special emphasis is placed on the use of small-volume injection tests, or diagnostic fracture injection tests (DFITs), to obtain an estimate of the in-situ kh because it is impossible to perform prefracture welltests in such a formation. The result of the DFIT analysis is then used to constrain the postfracture well-test analysis in a numerical-simulation model that includes fracture-filtrate-cleanup modeling. Post-fracture analysis showed that the initial proppant-pack damage is high and effective fracture length is much smaller than the created length, especially with crosslinked gel. The crosslinked-gel treatment was not able to clean up effectively, and therefore showed limited stimulation effectiveness. The first-ever water fracture in a gas reservoir performed in Europe showed a more significant production improvement during the short post-fracture test. The results from this well suggest that, as in North America, water fractures appear to have better initial production than crosslinked-gel fractures because of better fracture cleanup in European reservoirs with microdarcy permeability.
A New Analytical Method for Analyzing Linear Flow in Tight/Shale Gas Reservoirs: Constant-Rate Boundary Condition
Authors: Nobakht Morteza , Clarkson C.R.. R. 
Published: April 2012

Summary
Hydraulically fractured vertical and horizontal wells completed in shale gas and some tight gas plays are known to exhibit long periods of linear flow. Recently, techniques for analyzing this flow period using (normalized) production data have been put forth, but there are known errors associated with the analysis. In this paper, linear flow from fractured wells completed in tight/shale gas reservoirs subject to a constant-production-rate constraint is studied. We show analytically that the square-root-of-time plot (a plot of rate-normalized pressure vs. square root of time that is commonly used to interpret linear flow) depends on the production rate. We also show that depending on production rate, the square-root-of-time plot may not be a straight line during linear flow; the higher the production rate, the earlier in time the plot deviates from the expected straight line. This deviation creates error in the analysis, especially for flow-regime identification. To address this issue, a new analytical method is developed for analyzing linear-flow data for the constant-gas-rate production constraint. The method is then validated using a number of numerically simulated cases. As expected, on the basis of the analytical derivation, the square-root-of-time plots for these cases depend on gas-production rate and, for some cases, the plot does not appear as a straight line during linear flow. Finally, we found that there is excellent agreement between the fracture half-lengths obtained using this method and the input fracture half-lengths entered in to numerical simulation.
Advanced Upscaling for Kashagan Reservoir Modeling
Authors: Panfili P.. , Cominelli A.. , Calabrese M.. , Albertini C.. , Savitskiy A.. , Leoni G.. 
Published: April 2012

Summary
The Kashagan field is a huge carbonate formation located 4.5 km below the bottom of the North Caspian sea. The reservoir is saturated by overpressured light oil, and the development is based on first-contact-miscible gas injection.
The reservoir is highly stratified, with a fine sequence of depositional cycles and long-range lateral correlations. Three porosity systems (matrix, karst, and fractures) can be organized in two main environments: a massive, low-permeability, matrix-like inner platform and a highly fractured/karstified rim.
The reservoir geology is modeled by means of detailed geological grids consisting of tens of millions of cells, with vertical spacing of 1 m or even less to account for high-order depositional cycles. Geological grid cannot be used to run compositional simulations, and much-coarser grids, in which hundreds of geological layers are lumped in few tens of dynamic layers, are used by reservoir engineers. To minimize coarse-scale errors, an average lateral spacing of 250×250 m is used for both simulation and geological grid; nonetheless, upscaling remains a challenge. Traditional permeability (k*) upscaling methods, including flow-based methods, overestimate Kashagan field/wells production and injection potentials.
We implemented a method in which the outcome of the upscaling is effective transmissibility (T*) instead of k*. T* upscaling has been proposed in the past as an alternative to k* upscaling, but it is neither part of commercial workflows nor widely accepted in the reservoir-modeling community. In our T* upscaling, the solution of local flow problems around coarse-cell interfaces is used to compute coarse transmissibility. T* and k* upscaling were compared by simulating both single-phase and gas-injection problems, including platform and rim, using the results of fine-scale simulation as a reference. We considered (1) single-porosity simulations with geological grid populated by only matrix (first medium) and karst+fracture (second medium) properties and (2) dual-porosity/ dual-permeability simulations encompassing both media. Contrary to k* upscaling, T*-based coarse simulations perfectly replicate fine-scale field and well injection/production potentials.
Using T* upscaling as a cornerstone for company activities on Kashagan, we can run coarse-scale full-field simulations in a few hours without loss of consistency with the results provided by weeks-long, often unpractical, fine-scale simulations. On the contrary, the inaccuracy of k* upscaling would have required much finer and more computationally-expensive simulation grids together with the implementation of ad hoc multiphase upscaling.
Fracture and Fatigue of Polycrystalline-Diamond Compacts
Authors: Zacny K.. 
Published: April 2012

Summary
Four different batches of polycrystalline-diamond compacts (PDCs) were tested under monotonic and cyclic loadings. Initially, the mean load to fracture was recorded for each batch. In fatigue tests, the specimens were preloaded to between 75 and 95% of a batch mean static (S) strength and the R-ratio of 0.1 was used with frequencies of 10 and 20 Hz. It was found that some PDCs sustained greater than 106 cycles without fracturing. It was also noted that fracture force was reduced by 10 to 35% after the specimens were subjected to cyclic loading. This could indicate that fatigue weakens the structure of the PDC material. Tests conducted on two opposing edges of the same PDC buttons showed that the fracture on one side does not affect the strength of the opposing side. Thus, PDCs whose fracture or wear on flat areas is relatively small can be salvaged from the old bits, rotated 180°, and then rebrazed. Investigation of the fracture surface using a scanning-electron microscope (SEM) revealed that the fracture followed a transgranular path.
Best Practices for Conducting CO2-EOR Lab Study
Authors: Al-Otaibi Fawaz M. , Al-Mutairi Saad M. , Kokal Sunil L. , Funk James J. , Al-Qahtani Jassi F. 
Published: April 2012

Abstract
Energy demand has been escalating and is predicted to increase further in the coming decades. The dialogue on global climate change has the world abuzz on the primary green house gas, carbon dioxide. Both of these factors have created a perfect storm for the use of carbon dioxide for enhanced oil recovery. The petroleum industry is ideally suited for disposing of this green house gas. Each oil company (and others) has therefore stepped up its efforts in carbon dioxide utilization, either for EOR or sequestration. The injection of CO2 into a reservoir is not new. Indeed CO2 injection has established itself as a very efficient mechanism for increasing oil recovery.
To design a CO2-EOR or CO2 sequestration project, one requires a large set of appropriate experimental data for a given reservoir/fluid system. Where does one start? Even if the data have to be generated in a service lab, a good design requires some thought and effort. A search of the literature reveals no best practices for generating this dataset. This paper presents a comprehensive experimental design for conducting a CO2 laboratory study.
The essential components of a laboratory study for CO2 injection include measuring fluid-fluid interactions and fluid-rock interactions. Fluid-fluid studies include miscible displacement tests, measurement of minimum miscibility pressures, fluid properties of CO2-oil or CO2-brine mixtures including viscosity and density, asphaltene precipitation, and swelling. Fluid-rock interaction studies typically include coreflooding tests for determining the oil recovery potential, three-phase relative permeability, critical gas saturation, gas trapping and wettability changes. Each of these sets of experiments will be described in light of their best practice. The ultimate goal is to establish a procedure for generating a reliable and accurate dataset.
Modification to Equations of Gas Flow through Choke
Authors: Ling K. 
Published: April 2012

Abstract
Chokes are used to limit production rates to meet sale contract, comply with regulations, protect surface equipment from wearing out, avoid sand problems due to high drawdown, and control flow rate limited by capacity of the facility. Single gas phase flow through choke is vital to oil industry because not only an accurate estimation of gas flow rate guarantees a reliable supply to the end users, thus the predictable revenue from gas sale for the company, but also protect the equipment from breaking as a result of high gas rate. Nevertheless, importance of gas metering cannot be overemphasized. Gas flow through choke had been studied by numerous investigators, Different choke flow models are available from the literature, and they have to be chosen based on the flow regimes, that is, subsonic or sonic flow. The most common used flow equations developed by Shapiro, Zucrow and Hofmann are used for subsonic and sonic flow, respectively. Sonic flow happens when downstream to upstream pressure ratio is equal to critical pressure ratio.
A careful review of these equations indicated that they are not theoretically rigorous and give inaccurate gas flow rate for the real gas. Thus these equations need to be modified in order to be used to calculate gas flow rate under both flow regimes. After a thoroughly analysis and derivation we came up with equations that have solid base. New correlations that reconcile the issue caused by approximation method used to derive the old gas flow equations were based on both engineering judgment and physical phenomenon. The error in the old equation can be corrected with the new equations. New equations provide good approaches to quantify gas flow through choke.
Drift-Velocity Closure Relationships for Slug Two-Phase High-Viscosity Oil Flow in Pipes
Authors: Jeyachandra B.C.. C. , Gokcal B.. , Al-Sarkhi A.. , Sarica C.. , Sharma A.K.. K. 
Published: April 2012

Summary
The drift velocity of a gas bubble penetrating into a stagnant liquid is investigated experimentally in this paper. It is part of the translational slug velocity. The existing equations for the drift velocity are either developed by using the results of Benjamin (1968) analysis assuming inviscid fluid flow or correlated using air/water data. Effects of surface tension and viscosity usually are neglected. However, the drift velocity is expected to be affected by high oil viscosity. In this study, the work of Gokcal et al. (2009) has been extended for different pipe diameters and viscosity range. The effects of high oil viscosity and pipe diameter on drift velocity for horizontal and upward-inclined pipes are investigated. The experiments are performed on a flow loop with a test section with 50.8-, 76.2-, and 152.4-mm inside diameter (ID) for inclination angles of 0 to 90°. Water and viscous oil are used as test fluids. New correlation for drift velocity in horizontal pipes of different diameters and liquid viscosities is developed on the basis of experimental data. A new drift-velocity model/approach are proposed for high oil viscosity, valid for inclined pipes inclined from horizontal to vertical. The proposed comprehensive closure relationships are expected to improve the performance of two-phase-flow models for high-viscosity oils in the slug flow regime.
Using Cogeneration To Mitigate CO2 Emissions in Upstream Oil & Gas Activities
Authors: Welch M. J. 
Published: April 2012

Abstract
The production of oil and gas, and the various processes required to make these products suitable for transportation, is an energy-intensive operation. Provision of electrical power, process heat and mechanical power usually requires the combustion of fossil fuels with resultant CO2 emissions to atmosphere. Flaring of hydrocarbon-based waste gases also creates additional CO2 emissions at production facilities.
In many instances, taking a more global approach to facility design can greatly improve energy efficiency and hence reduce CO2 emissions. Employing Cogeneration technologies to generate both power and heat, or to recover waste heat from processes to generate electricity, can both reduce site emissions and help ensure security of electricity supply. It may also be possible to use waste-gas streams as a fuel for a Cogeneration plant, reducing the amount of premium fuel required and simultaneously eliminating gas flaring, or to sell any surplus electricity generated, turning a waste into a potential revenue stream.
There are numerous ways to configure a Cogeneration plant, depending on the ratio between the power and the heat required by the facility, the available fuels or waste heat sources, the form of process heat required and the actual electrical power demand. This paper will examine some of the different well-proven potential Cogeneration configurations based on Gas Turbines, Steam Turbines and Gas Engines, as well as looking at how the newer technologies of Organic Rankine Cycles and Concentrated Solar Power can be employed in Cogeneration applications.
With potential overall fuel efficiencies in excess of 75%, Cogeneration can offer significant CO2 reduction over separate generation of power and heat, from either an on-site or off-site facility, or imported power from a remote third-party power plant. The paper will discuss potential CO2 savings for certain common plant configurations and fuels.
Enhanced Drilling Solution for Top-Hole Sections on Jack up Wells with Environmentally-Improved Method and Dual Gradient Drilling Techniques
Authors: Scanlon T. , Medeiros F. 
Published: April 2012

Abstract
This paper describes the design and use of a subsea pumping system that allows improved construction of top-hole sections on offshore, jack up-drilled wells. This system has now been used for the first time offshore Brasil with positive results.
This subsea pumping system - the RMR™ (Riserless Mud Recovery) System - has been used extensively in other areas of the world, primarily on floater-drilled wells (Stave et al., 2005; Smith et al., 2010; Cohen et al., 2010, Scanlon, 2011). This previous RMR experience coupled with detailed discussions with Petrobras in Brasil resulted in this modified design for use on jack up-drilled wells, offshore Brasil.
Petrobras has a number of wells to drill in shallow waters offshore Brasil and needs a system that provides for minimal discharge of cuttings and drilling fluids to the ocean environment during drilling and installation of the conductor string, and that also enables better management of bottom hole pressure, when drilling the next hole section, inside the conductor string.
This new version of the RMR system has now been deployed offshore Brasil on two Petrobras wells. The system collected drilling fluids from the top hole section and pumped them back to the rig successfully, thus reducing the amount of cuttings and drilling fluids released into the natural ocean environment. The system was then used, after installation of the conductor string, to provide dual gradient drilling (DGD) techniques in the next hole section (for surface casing), resulting in improved penetration rates and well bore stability below the conductor shoe.
The RMR system used is described in this paper as well as the operational experiences realized on the first two wells and the improvements being made to prepare the RMR system and techniques for additional wells.
Fractional Flow in Radial Flow System—A Study for Peripheral Waterflood
Authors: Ling K. 
Published: April 2012

Abstract
The famous Buckley-Leverett displacement mechanism has been used to predict the performance of waterflood. With Buckley-Leverett method, oil recovery from waterflood is calculated and required water injection volume to achieve that oil recovery is estimated. This method does provide a very useful tool in waterflood design. Our experience in oil industry and a thorough literature review indicates that petroleum engineers used Buckley-Leverett method to analysis waterflood project directly without any adjustment basing on the real reservoir and production situations. By doing so, a lot of errors are introduced into the analysis.
It should be noted that Buckley-Leverett method assumed displacement occurs in a linear system. This is true for some waterflood scenarios while for others it is not. For some waterflood scenarios a radial system is more appropriate than a linear system. In this study we investigated the fractional flow in a radial system and derived the solutions to predict the performance of water displacing oil in radial system. With this radial displacement model, design and prediction of waterflood can be achieved by Buckley-Leverett method or our model, whichever fits the waterflood pattern. Considering the fact that many waterflood scenarios follow radial displacement, our model is an important supplement to Buckley-Leverett method.
Process Environmental Remediation Liabilities, Northern Region
Authors: Ventura Perez Jose Angel 
Published: April 2012

Abstract
Process describes the Environmental Remediation Liabilities (Dams and Contaminated Land), which was carried out in PEP Northern Region, which has optimized the process of identification, characterization and implemented best practices in remediation of soil, paying off in better performance environmental, and under budget year to the enforcement of environmental regulations.
The work was created in four stages: identification, to specify location and census, Characterization, which defined the terms and scope of characterization, developed an agreement with technical and economical choice to have a comprehensive characterization of contaminated sites hydrocarbons (environmental liabilities), reducing the uncertainty for the remediation, remediation, with the selection of sustainable methodologies and with less impact, and Management, to regulate all activities. The results, main, were:
We defined the requirements for a comprehensive characterization of the site.
We obtained a 27% savings in Dams and 80% in soils in the selected proposal.
Was determined with greater accuracy, surface and volume to remedy, providing certainty to the census of contaminated sites
We have characterized 140 dams and 148 hectares of contaminated land
We identified 92 dams and 2.84 ha, which do not require remediation for the characterization values within standard registration.
In the remediation, sustainable techniques were selected as co-processing, chemical oxidation and bioremediation, obtaining the remediation in the period 2010-2011, 262 dams and 83.29 hectares of environmental liabilities.
186 Management of remediation programs at the SEMARNAT DGGIMAR of which 99 have been resolute.
BC-10: The First Successful Replacements of Caisson ESPs in Deepwater Brazil
Authors: Harris D. , Bode W. , Martinez I. , Rivera R. , Hines Natalya 
Published: April 2012

Abstract
The Parque das Conchas development is located in the BC-10 block 75 miles southeast of Vitoria int the Campos Basin, offshore Brazil. Shell is the operator with a 50% equity share, with joint venture partners Petrobras (35%) and ONGC (15%). The current development consists of three hydrostatically pressurized medium to heavy oil reservoirs (Abalone, Ostra and Argonauta B West) in water depths ranging from 5430 ft to 6310 ft (1655 m to 1923 m). One of the key enabling technologies at the heart of the subsea system infrastructure is the mudline boosting system consisting of Modulo de Bombeio or Pumping Unit (MOBO) caisson ESPs installed inside Artificial Lift Manifolds (ALMs) 1). Oil from the individual subsea wells flows into the MOBO caisson ESPs and from there the ESPs pump the oil up to the floating production, storage and offloading (FPSO) vessel. The ALMs are located approximately 5½ miles (8.85 km) from the FPSO (see Figs. 1 and 2).
This paper will describe how the design for these special longlife ESPs was developed, how a stack-up test was performed on land in the US, and how the pumps were deployed in the field. In the second part, the first operations for pulling two of the ESPs are described. The whole assembly consisting of the MOBO, 32-in. caisson and ESP completion was lifted in open water to the rig with a total assembled weight of 169 tons (171.7 metric tons).