bluuebunny/crossref_metadata_2025_split huggingface dataset:
Ultralightweight Proppants: An Effective Approach To Address Problems in Long Horizontal Gravel Packs Offshore Brazil
Authors: Jardim Neto A.T. , Prata F.G.M. , Gomez J.R. , Pedroso C.A. , Martins M.O. , Silva D.N. 
Published: November 2012

Summary
Operators developing reservoirs and producing them from deep and ultradeepwater wells are pushing the technical limits regarding horizontal extension. Deepwater wells completed in unconsolidated formations usually have low fracture gradients, severe leakoff zones, and/or significant washouts. Long horizontal open holes, therefore, may become technically difficult or economically unfeasible to gravel-pack with the use of conventional fluids and gravels.
Typical completions in offshore Brazil start from a 9⅝ - or 10¾-in.casing, in which a 5½-in. premium screen and tubular string is hung along an open hole drilled with an 8½- or 9½-in. bit. Horizontal extensions range from 980 to 4,000 ft. A variety of openhole gravel-pack techniques proved to be complex and costly, but ultralightweight (ULW) proppants have enabled simpler and more-cost-effective gravel packing in these longer horizontal open holes. The reduced gravel density allows a significant reduction in pumping rate that avoids fracturing the formation, minimizes fluid loss, and eliminates the risk of premature screenout caused by excessive gravel settling.
ULW-proppant technology was introduced to Brazil in 2005 and has been applied successfully to gravel pack wells under extreme conditions such as low fracture gradient, severe fluid loss, and washed-out zones. ProppantULW-1.25 has proved to be effective for packing wells with narrow sections through the openhole interval, frequently found in horizontal wells completed through shale zones that are isolated by reactive packers and/or mechanical external casing packers. ULW-1.75 was introduced in Brazil in 2007 and has largely replaced ULW-1.25 for gravel packing wells in which an improvement in the operational pumping window is required. A combined package comprising ULW-1.75 during the alpha-wave phase and ULW-1.25 during the beta-wave phase is also discussed. This paper summarizes the procedures and results of almost 60 wells that have been gravel packed with the use of ULW-proppant technology pumped for a local operator.
Advanced Drilling Simulation Environment for Testing New Drilling Automation Techniques and Practices
Authors: Cayeux Eric , Daireaux Benoît , Wolden Dvergsnes Erik , Leulseged Amare , Torstein Bruun Bjørn , Herbert Mike 
Published: November 2012

Summary
Newly developed drilling automation systems locate a computer interface between commands issued by the driller and instructions transmitted to the drilling machinery. Such functions are capable of faster and more precise control than can be achieved by an unaided operator and thus can help drilling within narrow margins. To ensure that these systems work properly in all circumstances, an advanced drilling simulator has been developed to enable testing under a wide range of simulated conditions.
The environment described in this paper uses hardware in the loop (HIL) simulation to verify that the automation techniques being tested respond correctly in real time. Rigorously validated physical models of the drilling process simulate the response of the well to the commands given to the drilling machines. Abnormal drilling conditions (e.g., packoffs, kicks) and equipment or machine-related problems (e.g., plugged nozzles, power shortage) are convincingly recreated.
The drilling simulator models the behavior of surface equipment such as the activation of gate valves to line up different pits or the flow in the mud return. It simulates changes in the drilling fluid properties when mixing additives to the mud. It is therefore possible to focus training sessions on cooperation between different groups at the wellsite. This is particularly useful when planning the introduction of drilling automation that involves new work procedures as a result of automation and adaptation of the drilling team to a new operational environment.
Drilling operations are becoming more and more complex. Automation has the potential to provide large improvements in efficiency and safety, but automation technologies must be implemented correctly at the workplace. Just as the aviation industry has used simulated environments for decades, drilling simulation environments are the key to the safe and successful implementation of drilling automation and the development of crew skills to face future challenges.
The Design of BHA and the Placement of Magnetometer Sensors Influence How Magnetic Azimuth Is Distorted by the Magnetic Properties of Drilling Fluids
Authors: Waag Tor Inge , Torkildsen Torgeir , Amundsen Per Amund , Nyrnes Erik , Saasen Arild 
Published: November 2012

Summary
The magnetic property of drilling fluid is one of the substantial error sources for the determination of magnetic azimuth for wellbores. Weight material, cuttings, clay, and other formation material in addition to metal filings from tubular wear may distort the magnetometer readings. This effect is obviously linked to the amount and kind of magnetic material that is in the drilling fluid, and the development of corrective means has therefore highlighted the drilling fluid. The problem has been studied by laboratory experiments and analyses of downhole-survey data. However, there are several inconsistencies in the results, and the phenomenon is not understood fully. We focus on the geometric properties of the bottomhole assembly (BHA) and the magnetic directional tool in this study.
The influence on directional measurement while drilling (MWD) from drilling fluids has been studied using finite-element modeling techniques. The simulations have been performed for several cases with realistic representations of MWD-tool geometries and varying location of BHA vs. the wellbore. One important result is that for situations with perfect axial symmetry, the magnetometer readings are attenuated proportionally to the square of the magnetic susceptibility. Because the magnetic susceptibility is a small number, the effect on magnetometer readings is generally negligible. However, if the symmetry is broken, the distortion on the magnetometer readings can be increased significantly. This means that segregation of cuttings, metal filings, or weight material can have a strong influence on the strength of the measured magnetic fields.
With a collar-based tool that is asymmetric by nature, the model shows a complex distortion picture. The influence varies with the tool-face angle and shows both attenuation and amplification. The distortion maxima and minima for the two crosssectional magnetometers do not coincide. These findings underline how difficult it will be to find a straightforward corrective action.
The results from the simulations give increased knowledge about the influence from the magnetic properties of the drilling fluid. This is essential for accuracy estimation and multistation analysis of magnetic-survey data. Furthermore, the results demonstrate the importance of considering the geometry of the BHA and the tool and of the sensor placement when performing the mechanical design.
Design Considerations of Waterflood Conformance Control With Temperature-Triggered, Low-Viscosity Submicron Polymer
Authors: Izgec O.. , Shook G.M.. M. 
Published: November 2012

Summary
In waterfloods, the existence of highly conductive thief zones causes poor volumetric sweep efficiency, resulting in early breakthrough and excessive production of water. A conventional strategy of redirecting injection by closing off perforations yields short-term benefits because diversion occurs near the wellbore. As an alternative, temperature-triggered submicron polymers with low viscosity (popping agents), which give an opportunity for conformance control deep in the reservoir, have been introduced in recent years. This technology aids conformance control by plugging the high-permeability zones and diverting the fluid to the unswept portion of the reservoir.
Understanding the critical parameters that lead to a successful treatment and accurate determination of the slug size are two important criteria for a technically and economically successful treatment. In this study, we first investigate the effect of different parameters on the success of a conformance control treatment. A comprehensive design-of-experiments (DOE) study resolves the effects (and combined effects) of kv/kh, treatment fluid concentration, thief-zone to matrix-permeability ratio, mobility ratio, and location of the placement in the reservoir. Next, a methodology is developed for accurate determination of the conformance slug size. The method is built on the temporal moment and residence time distribution analysis (RTDA) of interwell tracers. Dynamic flow- and storage-capacity curves are used to identify the optimum slug size.
3D thermal computer simulations show that thief-zone to matrix-permeability ratio and placement location of the polymer are the most important parameters that affect the success of a treatment. The most desirable setting is placement of the polymer deep in the reservoir, closer to the producer within high kv/kh reservoirs. Furthermore, the computer simulations confirm the power of the new technique for optimal slug-size determination. This new technique can avoid underestimation of the volume that must be treated, which is critical for the success of a treatment.
A Pilot Carbon Dioxide Test, Hall-Gurney Field, Kansas
Authors: Willhite G.P.. P. , Byrnes A.P.. P. , Dubois M.K.. K. , Pancake R.E.. E. , Tsau J.-S.. -S. , Daniels J.R.. R. , Flanders W.A.. A. 
Published: November 2012

Summary
A pilot carbon dioxide (CO2) -miscible flood was initiated in the Lansing-Kansas City C formation in the Hall-Gurney Field, Russell County, Kansas. The reservoir zone is an oomoldic limestone located at a depth of approximately 2,900 ft. The pilot consisted of one CO2 injection well and three production wells. Continuous CO2 injection began in December 2003 and continued through June 2005, at which point 16.19 million lbm of CO2 had been injected into the pilot area. Injection was converted to water in June 2005 to reduce operating costs to a break-even level with the expectation that sufficient CO2 was injected to displace the oil bank to the production wells by water injection. By March 2010, 8,736 bbl of oil had been produced from the pilot. Production from wells to the northwest of the pilot region indicated that oil displaced by CO2 injection was produced from five wells outside of the pilot area, to the northwest. Approximately 19,166 bbl of incremental oil was estimated to have been produced from these wells as of March 2010. There was evidence of a directional permeability trend toward the northwest through the pilot region. The majority of the injected CO2 remained in the pilot region, which was maintained at or above the minimum miscibility pressure (MMP). Although the four-well pilot was uneconomical, the estimated oil recovery attributed to the CO2 flood is 27,902 bbl, which is equivalent to a gross CO2 usage of 4.8 Mcf/bbl.
Establishing Key Reservoir Parameters with Diagnostic Fracture Injection Testing
Authors: Nojabaei B.. , Kabir C.S.. S. 
Published: November 2012

Summary
Diagnostic fracture injection testing (DFIT) is an invaluable tool for evaluating reservoir properties in unconventional formations. The test comprises injection of water over a short time, starting a fracture at the end of a well's horizontal section, followed by a long shut-in period. Analysis of the falloff data with the G-function plot reveals the fracture-closure pressure, and the fracture pseudolinear-flow period.
In most tests, wellhead-pressure (WHP) measurements are used because of cost considerations. A wellbore-heat-transfer model is used to allow conversion of WHP to bottomhole pressure (BHP) by accounting for changing fluid density and compressibility along the wellbore. This model, in turn, allowed us to assess the quality of solutions generated with the WHP data. For DFIT analysis, we adapted the modified-Hall plot for the injection period, whereas both the pressure-derivative and G-function plots were used for the analysis of falloff data. The derivative signature of the modified-Hall plot allows unambiguous estimation of the fracture breakdown pressure (pf,) during the injection period. As expected, the pf, always turns out to be higher than the fracture-closure pressure (pfc), estimated with the two methods during pressure falloff, thereby instilling confidence in the solutions obtained.
A statistical design of experiments with coupled geomechanical/fluid-flow simulation capabilities showed that the formation permeability is by far the most important variable controlling the fracture-closure time. Mechanical rock properties, such as Young's modulus of elasticity and the Poisson's ratio, play minor roles. In microdarcy formations, a longitudinal fracture takes much longer to close than a transverse fracture.
Simulation of Drilling Fluid Filtrate Invasion Near an Observation Well
Authors: Chassagne Romain L. , Hammond Paul S. 
Published: November 2012

Summary
We used a commercial reservoir simulator to study, first, the dissipation of aqueous drilling fluid filtrate invasion around a cased observation well in an oil-saturated formation under the action of capillary pressure and, second, the interaction of a waterflood front with the cased well and remaining invaded zone. Hysteretic behavior of the capillary pressure and relative permeabilities is critically important to these processes and is taken into account by the use of the Carlson model, with the various bounding drainage and imbibition curves computed from a pore network model.
Filtrate invasion into a hydrocarbon formation influences the readings of well-logging tools. Although this phenomenon has been known, and corrected for, for many years, uncertainty remains with regard to the long-time behavior of invasion around observation wells where no flow in or out of the formation occurs after completion, and with regard to the influence of formation wettability. We find that after sufficient time, the invaded zone dissipates completely in a water-wet formation, but some invasion always remains in the oil/mixed-wet case. Nonwetting-phase trapping, manifested through relative permeability hysteresis, is the cause. Because trapping affects the values and the endpoints of the relative permeability curves, a waterflood front passing across an observation well is more distorted in the oil/mixed-wet case. The simulation results allow us to understand how logging-tool measurements made in cased observation wells are influenced by drilling-fluid invasion and will therefore lead to improved interpretation. This study shows strong links between the wettability of the formation and the persistence of invaded zone saturation and between invaded zone saturation and the distortion of subsequent flood fronts.
Application of Multirate Well Tests to Scale Management: Part 2—Interpretation of MRTs With Known Produced-Water Origin
Authors: Tjomsland Tore , Sandøy Bernt , Fadnes Finn Hallstein , McCartney Ross 
Published: November 2012

Summary
Several multirate separator tests (MRTs) have been undertaken on wells in the Veslefrikk field that are on commingled production from the Brent Group and Intra Dunlin Sand (IDS). During these tests, produced-water (PW) samples were also collected. Integrated analysis of the results of interpretion of the PW analyses and the MRT results has provided a range of information for each production zone, including the nature and composition of the PW, the seawater fraction of these produced waters, the fraction of total water flow being produced, pressure, productivity index, oil and water rates, and water cut. This information can reduce the need for running production-logging tools (PLTs), allows the scaling potential between the deeper and the shallower zones to be evaluated, aids squeeze-treatment design, is beneficial for predicting formation damage from crossflow, and aids water-shutoff decisions.
In an accompanying paper, McCartney et al. (2012) describe how PW analyses from the MRT are interpreted to determine— among other parameters—the amount of water produced from each zone (water allocation) at each of the test rates during an MRT. In this paper, the methods of analyzing these results in combination with separator-test data are described with the aid of a field example to demonstrate how they provide detailed information about the downhole conditions and zone properties of the well. On the basis of the analysis, a set of well interventions was recommended. Following confirmation of the principal MRT results by a PLT, some of the recommended interventions have been performed successfully. Experience from Veslefrikk suggests that MRTs can be considered as a possible replacement for running PLTs or as an additional source of data that can be acquired more frequently.
A Dynamic Model of Percolating Gas in a Wellbore
Authors: Hauge E.. , Stamnes Ø.N.. N. , Aamo O.M.. M. , Godhavn J.-M.. -M. 
Published: November 2012

Summary
The two-phase dynamics of gas percolating up a vertical well filled with water is described by two ordinary-differential equations and algebraic relations. We model the gas as bubbles distributed with a distribution function along the well. The model is based on first principles and accommodates tracking of the front of the gas. An unscented Kalman filter (UKF) is used together with the model and wired-drillpipe (WDP) pressure measurements to estimate the liquid-holdup profile as the gas is circulated out of the well. The performance of the model and the method of estimation are compared with results from a state-of-the-art simulator.
A Novel Tool To Improve the Rate of Penetration–Hydraulic-Pulsed Cavitating-Jet Generator
Authors: Fu J.. , Li G.. , Shi H.. , Niu J.. , Huang Z.. 
Published: November 2012

Summary
On the basis of the analysis of the jet-modulating mechanism, a novel tool—a hydraulic-pulsed cavitating-jet generator (HPCJG)— is designed to further improve the rate of penetration (ROP). The HPCJG combines the advantages of a pulsed jet and a cavitating jet. When the drilling fluid flows through this tool, the fluid will be modulated to the pulsed and cavitating jet by application of the impellers and by entering into the self-resonant chamber. During this process, a pulsed cavitating jet is formed at the outlet of the bit nozzle. Because of jet pulsation, cavitating erosion, and the local negative-pressure effect, the cleaning efficiency of the well-bottom cuttings and the ROP will be improved. Laboratory and oilfield tests have indicated that the pulsed-pressure amplitude and the pressure drop of the generator increase with the increase of the flow rate. However, the frequency of the pressure pulsation is invariable in this process. This generator has been applied to more than 100 wells in eight oil fields throughout China. The results show that the maximum density of the test drilling fluid is 1.93 g/cm3, the maximum test-well depth is 6162 m, and the operation time of the generator is more than 230 hours (the maximum operation time recorded was more than 520 hours). Furthermore, the average ROP was increased by approximately 16.7% to 104.4%. In conclusion, the generator has the characteristics of a simple structure, has a long lifetime, is able to adapt well with existing drilling equipment, and can provide a safe and efficient drilling technique for deep wells.
Geostatistical Population-Mixture Approach to Unconventional-Resource Assessment With an Application to the Woodford Gas Shale, Arkoma Basin, Eastern Oklahoma
Authors: Olea Ricardo A. , Charpentier Ronald R. , Cook Troy A. , Houseknecht David W. , Garrity Christopher P. 
Published: November 2012

SummaryEvaluation of resources such as tight sands and gas shales requires the formulation of assessment models that are different from those used for the inference of conventional resources. Formulations in present use are based in classical statistics that ignore the partly organized and partly random geographical variation of attributes related to the occurrence of hydrocarbons. This paper is the third in a series of methodological tests aimed at enhancing the assessment of unconventional resources through more-effective use of implicit and explicit information contained in the data, moreaccurate evaluation of resources, and more-informative display of results. Reprocessing of estimated-ultimate-recovery (EUR) data at the Woodford gas shale in Oklahoma shows that subdivision of the play into areas as homogeneous as possible can produce results comparable to those obtained using several variables correlated to local productivity.
Definitive Petrophysical Evaluation of Thin Hydrocarbon Reservoir Sequences
Authors: Majid Azlan A. , Worthington Paul F. 
Published: November 2012

SummaryThe petrophysical evaluation of thinly-bedded sand/shale sequences is strongly dependent on the way in which layered and dispersed shales are taken into account. There are two underpinning issues: the recognition of thin bed geometries and the estimation of shale content from lithology logs. The first of these is managed through a scenario approach, whereby different downhole scenarios are set out according to specified ranges of bed thickness. Each range has its own interpretation protocol. The second issue relates to the inherent overestimation of clay-mineral volume fraction by shale indicators and its impact on the petrophysical evaluation of thinly-bedded sand porosity. This shortcoming is managed by applying a validated scaling factor to log-derived estimates of shale volume fraction so that these become workable estimates of clay-mineral fraction for the porosity evaluation of sand layers. Both these problems become more acute for thinner beds. These two key issues are addressed conjunctively through interpretive workflows, each of which relates to a discrete range of bed thickness and uses fit-for-purpose petrophysical data sets. In particular, the multicomponent induction log is adopted as a pivotal technology for the evaluation of sand resistivity within thinly-bedded sand/shale sequences. The objective is to achieve a sound petrophysical interpretation for each downhole situation. Therefore, groundtruthing through core data is advocated where this allows the shale problem to be managed better. The outcome is a systematic approach to thin-bed evaluation, based on prescribed data inputs that optimize project effectiveness. The benefits are illustrated through case histories that demonstrate a securable upside in projected hydrocarbon volumes.
Accuracy of prediction of birth weight by fetal ultrasound
Authors: Bajracharya J , Shrestha NS , Karki C 
Published: November 2012

Introduction: Estimation of accurate fetal weight is essential in obstetrical management and we aim to see the accuracy of fetal ultrasound in estimating birth weight in our setting. Method: 150 women with full term singleton pregnancy leading to live birth were included in the study. Prenatal fetal ultrasound database was reviewed for the fetal biometry and fetal weight estimation and delivery records were reviewed for actual birth weight. Error in estimation was calculated.Result: The study showed that fetal ultrasound using Hadlock.s formula has error in estimation of fetal weight by about 290 gm ± 250 gm. In 40% of the cases, there is an error of estimation by more than 10% compared to actual weight. Conclusion: There is a significant error in the estimation of the fetal weight. Depending only on the fetal ultrasound for the estimation of fetal weight can lead to unnecessary obstetrical intervention. It is necessary to correlate the ultrasound findings with clinical examination.Health Renaissance; September-December 2012; Vol 10 (No.3);236-238DOI: http://dx.doi.org/10.3126/hren.v10i3.7053