bluuebunny/crossref_metadata_2025_split huggingface dataset:
Yates Field Steam Pilot Applies Latest Seismic and Logging Monitoring Techniques
Authors: Snell J. S. , Close A. D. 
Published: December 2007

Abstract
A steam pilot in the Yates Field is underway to assess the economic viability of improving gravity drainage in the gas cap of the fractured San Andres reservoir. A thorough monitoring program has been implemented which employs the latest in seismic and logging technology. As steam is injected, downhole geophones monitor passive seismic events caused by thermal expansion of the rock to estimate the areal and vertical extent of the heated zone. At the same time, time-lapse carbon-oxygen logs are being used to monitor changes in oil saturation behind the thermal front. Careful design and planning are required to dedicate several wells in the pilot area solely to the application of these technologies. Results from the geophones and repeat logs will be combined to estimate the volume of oil mobilized as a result of steam injection. This volume will be compared to oil production increases and with results from fluid sampling and temperature monitoring in the pilot area to assess the economic viability of the steam pilot.
The NMR T2 Response of Crude Oils at Elevated Temperatures
Authors: Jacob James , Davis Lorne A. 
Published: December 2007

Abstract
Until recently, most nuclear magnetic resonance (NMR) measurements in support of lab petrophysics and well logging were conducted at room temperature. However, the T2 relaxation of bulk crude oils strongly depends on temperature. Measurement of the crude oil relaxation response at reservoir temperatures is needed for optimal interpretation of log data.
This work used a Carr-Purcell-Meiboom-Gill (CPMG) pulse sequence to measure the NMR T2 relaxation at 2 MHz. Four stock tank crude oils were studied over the temperature range 30-100°C at a constant pressure of 300 psig. For comparison, the T2 temperature response of five viscosity standards was measured over the same range and compared to the crude oil data. A two-component exponential decay described all the data. As expected from the temperature dependence of translational diffusion, there is not a universal curve that fits all hydrocarbon mixtures. The standards and the crudes did not fit a single curve.
The observed oil T2 varied directly with absolute temperature and inversely with the viscosity. For the crude oils, the log mean T2 was related to a viscosity value calculated from the stock tank oil viscosity correlation as developed by Beggs and Robinson and modified by Egbogah (EBR). This T2 relation did not agree with a T2 correlation (SRVTM, 1994) developed at room temperature from oil samples of differing viscosity (0.7 to1000 cp). When the viscosity of one of the crude oils was measured as a function of temperature, that data then fit the SRVTM room temperature T2 correlation. Viscosity values derived from correlations based only on API gravity are evidently insufficient to make close estimates of crude oil T2 relaxation at elevated temperatures.
One of the crudes was a distinct outlier from the others. The composition of this sample suggests further investigations into the T2 relaxation of oil-based mud filtrate and mixtures of crude and oil-based mud filtrate.
Crude and Hydrocarbon Measurement Technologies
Authors: Basrawi Y. F. 
Published: December 2007

Abstract
The paper talks about the principles and applications of current and emerging crude and hydrocarbon flow measurement technologies. It highlights the applications of flow metering technologies, in the world and in the Kingdom of Saudi Arabia. Emphasis is put on better precision and higher accuracy in volumetric and mass custody and royalty transfer through put measurement, of crude and hydrocarbon fluids. Through finer precision and higher accuracy, when applied to exports and domestic consumption, proper accountability can be achieved and tremendous cost savings realized. " We cannot be held accountable for what we can not measure". Topics of presentation consist of the science of measurement, application of current and emerging technologies in the world of hydrocarbon measurements and the proactive role Saudi Aramco is playing in this research and application. The technologies that will be briefly discussed are, the use of the master meter in certifying crude and product meter provers as an applied technology and its comparison in accuracy to conventional methods of meter prover certification. Other devices consist of the principles and sciences of gas flow measurement, the various water-in-crude detection instruments, currently under research in Saudi Aramco and the application and viability to custody measurement, where accuracy is far more stringent than that of process condition, of the new mass and hellicoidal flow meters.
Automatic Control of Unstable Gas Lifted Wells
Authors: Jansen Bård , Dalsmo Morten , Nøkleberg Lars , Havre Kjetil , Kristiansen Veslemøy , Lemetayer Pierre 
Published: December 2007

Abstract
Oil production wells on gas lift are sometimes unstable at low gas lift rates, even though steady-state flow analysis gives most efficient production at these gas lift rates. Unstable production, often called heading, may lead to periods of reduced or even no liquid production followed by large peaks of liquid and gas. This results in average oil production less than expected, and oil and gas production less than the systems design capacity to allow for the production peaks without causing shutdowns.
To solve the problem the amount of lift gas is normally increased beyond the most optimum rate. When the lift gas supply is limited, other gas lifted wells must then be shut in.
This paper describes one field proven sequence based automation for oil production, plus a new model-based automatic controller. Both technologies solve the problem of unstable production from gas lifted wells through manipulation of the production and/or the gas-injection chokes. The sequence-based automation and the model-based controller stabilize the production at operating points that would be unstable under standard operation. Field measurements such as wellhead pressure, annulus pressure etc. are inputs to the controllers (or are used by the controller).
Examples are given of the model-based controller working together with realistic transient flow models of gas lift wells. Testing of the model-based controller on real unstable wells is planned.
Experimental Investigation of Proppant Flowback Phenomena Using a Large Scale Fracturing Simulator
Authors: Goel Naval , Shah Subhash N. 
Published: December 2007

Abstract
This paper evaluates the maximum flow rate before the sand production initiates while flowing back a reservoir after the hydraulic fracturing treatment. The experiments are performed in a high pressure slot which simulates a fracture. The slot is a parallel plate device, which is 7 ft high and 9 1/3 ft long with provisions for varying fracture gap width. The slot is filled with proppant to simulate a propped fracture, then, the closure pressure is applied with 12 actuators to simulate confining pressure on the proppant pack. Water is pumped into the slot to simulate flowing back of the fracturing fluid. The water flow rate is varied till the proppant pack destabilizes, and the sand production begins. The sand distribution is observed in the fracture with a vision system.
The experimental results show that the critical water flowback rate decreases as the closure pressure increases, or when the fracture gap width increases. However, the sand-free maximum water flow rate increases as the sand size increases for a given fracture gap width. Lastly, the cumulative sand production decreases as the closure stress decreases at a particular flow rate. The visual observations of the proppant flowback phenomena show that the sand production initiates close to the perforation. After the initiation of the sand flow, continued pumping of the water results in sand production through a channel formed in the proppant pack.
Attrition Resistant Cracking Catalysts A New Refining Standard
Authors: Higginson G.W. , Upson L.L. , Witoshkin A. , Schwint I.A. 
Published: December 2007

Over the past several years, refiners have paid increasing attention to the subject of particulate emissions from stacks. One of the important refining processes that has felt the impact of this is field catalytic cracking. In many cases this has already resulted in the installation of costly electrostatic precipitators where none previously existed. precipitators where none previously existed. At the same time, the catalyst industry has responded with a number of new high activity catalysts with improved attrition resistance qualities. Not all of these "harder catalysts" attain the same. This is probably due to differences in manufacturing approach to the individual products.
Hondry's HFZ catalysts have shown the ability to reduce stack losses from FCC units. These catalysts are manufactured by the Minerals and Chemicals Division of Engelhard Minerals and Chemicals Corporation and are marketed exclusively in the Western Hemisphere by the Houdry Division of Air Products and Chemicals, Inc., elsewhere by Engelhard.
This article describes some of the recent commercial experiences with HFZ catalysts which strongly support the initial commercial evidence of the attrition resistance characteristics of these catalysts.
Win-Win Development Strategy for a Unitized Field: Fairley Baram
Authors: Yusoff Shahbehri , Salleh Alias , Kamari Yusoff Mohd. 
Published: December 2007

Abstract
Fairley Baram Unitized Field straddles the border of Brunei and Sarawak, Malaysia and is among the identified marginal fields that contain far greater HIIP than previous estimation. Realizing the upside potential, both joint operators, Petronas Carigali Sdn. Bhd. (PCSB) and Brunei Shell Petroleum (BSP) formed a team to review and plan for the field further development and appraisal activities.
The development phase of the campaign proved greater oil columns in proven reservoirs and developed 5.2 MMstb of oil reserves. The appraisal phase proved that the incised valley is predominantly shale filled with sand body at the base. The shale interval provides a seal and separation for reservoirs abutting to it. Deeper sands underlying the developed reservoirs were also proven to be hydrocarbon bearing. A revised volumetric incorporating the new data from the campaign indicates that the HIIP is substantially bigger than the pre-review volumes.
The re-processed 2D seismic, petrophysical, production and well data were fully utilized in the study. The deliverables are re-interpreted structural maps, in addition to the newly formulated depositional concept and revised petrophysical input. The depositional model is interpreted as an incised valley with slumping due to the tectonic movement or fall in sea level.
This paper discussed how the integrated field review enabled the team to better understand the field performance and better managed the uncertainties. The integrated field review also demonstrated that it is possible to turn around a ‘brown’ field and improved the field production rate by identifying additional proved develop reserves and at the same time replenish reserves from the appraisal targets.
Effect of Bridging Adsorption on the Placement of Gels for Water Control
Authors: Zitha Pacelli L. J. , Darwish Mohamed M. I. 
Published: December 2007

Abstract
Polymers and gels have been used in the past to reduce water production (water shutoff). However, only a limited number of treatments have been reported as being successful. The control of the placement of the chemicals is key factor ensure the success of water shutoff treatments. Due to the risk inherent in the use of plugging agents (polymers and gels) it became current practice to use zone isolation or dual fluid injection to ensure the placement of the chemicals in the high permeability water bearing water streaks. However mechanical zone isolation is costly and, more significantly, cannot be practiced in most wells.
Polymer and gel treatments without zone isolation (i.e., bullheaded treatments) may be expected to have a wider range of applicability provided the penetration of the chemicals in the low permeability oil bearing streaks is very small. The bridging adsorption of flexible polymers has been identified as a mechanism that can help achieving such low penetration and divert the chemicals from low (oil bearing) to high (water bearing) permeability streaks.
The aim of this work is twofold. First we improve the theory for the bridging adsorption previously presented to take into account the effect of the adsorption energy. Secondly we develop a model for the placement of polymers in linear and radial layered reservoir systems, taking into account the layer and bridging adsorption mechanisms and the Non-Newtonian character of the polymeric fluids. Steady state flow conditions are assumed for mathematical simplicity.
We found that the rheology of the polymer and the layer adsorption as such have a limited influence on the penetration depths of the polymers in the different layers as has been discussed in the literature. When bridging adsorption is taken into account, however, the penetration in the low permeability layers decreases sharply confirming our previous observations. Hence a good bullheaded placement may be achieved if the bridging adsorption is well controlled.
Summary of ASP Pilots in Daqing Oil Field
Authors: Demin Wang , Jiecheng Cheng , Junzheng Wu , Zhenyu Yang , Yuming Yao , Hongfu Li 
Published: December 2007

Abstract
Studying zones, geological sediments, oil and water, etc. of different characteristics, suitable ASP systems mainly with alkylbenzene sulfonate, bio-surfactant, NaOH, Na2CO3 and polymer were screened. After getting good results in laboratory studies, five ASP pilot tests have been conducted with different well spacings, zones and at different locations etc. Our aim was to study: 1) the injectivity and productivity of ASP systems; 2) the damage to the reservoir with different kinds of alkaline; 3) the method of lift and how to increase very low productivity; 4) Chromatographic separation with different well spacing; 5) the effect of this EOR method and its potential; 6) its technical and economical benefits.
Both laboratory and pilots studies showed that different zones, oil and water, and different surfactant components all require different ASP systems; bio-surfactant is compatible with alkylbenzene sulfonate; and no matter what kind of alkaline where selected in the pilot, theoretically, there is some damage to the zone, but the damage to the reservoir was not significant in the pilots, the same for chromatographic separation. Numerical simulation and pilot results both showed that more than 20% OOIP oil recovery were obtained over that of water flooding. The actual production data was better than numerical simulation. Even in a reservoir with long-term 100% water cut, the chemical cost per ton of incremental oil is around 30$ to 40$. Especially in a very low oil price situation in the world today, this method can obtain good benefits both technically and economically.
Over all, the success of these ASP flooding pilots in Daqing Oil Field are good examples on enhanced oil recovery with similar types of reservoir sediment as Daqing, and also provides a new method to achieve sustained development of resource developing companies.
Improved Production and Sand (Cold) Production in Conventional and Heavy Oil Reservoirs-A Field Case and Simulation
Authors: Wang Yariong , Chen Carl C. 
Published: December 2007

Abstract
A coupled reservoir-geomechanics model is developed to simulate the enhanced production phenomena in both heavy oil reservoirs (Northwestern Canada) and conventional oil reservoirs (North Sea). The model is developed and implemented numerically by fully coupling an extended geomechanics model to a two-phase reservoir flow model. Both the enhanced production and the ranges of the enhanced zone are evaluated, the effect of solid production on oil recovery are analyzed. Field data for solid production and enhanced oil production, collected from about 40 wells in the Frog Lake (Lloydminister, Canada), are used to validate the model for the cumulative sand and oil production. Our studies indicate that the enhanced production is mainly contributed (1) by the reservoir porosity and permeability improvement after a large amount of sand is produced, and (2) by higher mobility of the fluid due to the movement of the sand particles. A relative permeability reduction after a certain period of production may result in a pressure gradient increase, which can promote further sand flow. This process can further improve the absolute permeability and the overall slurry production. Our results suggest that a sand production can reach up to 40% of total fluid production at the early production period and decline to a minimum level after the peak, which can generate a high-mobility zone with a negative skirt near the formation. Such an improvement reduces the near well pressure gradient so that the sanding condition is weakened, and permits a easier path for the viscous oil to flow into the well. Our studies also suggest that the residual formation cement and capillary pressure are the key factors to affect the cumulative sand production, a crucial factor to determine the success of a cold production operation and improved well completion.
Ultimate Evaluation of the Alkali/Polymer Combination Flooding Pilot Test in XingLongTai Oil Field
Authors: Zhang Jifen , Wang Keliang , He Fengyun , Zhang Fengli 
Published: December 2007

Abstract
A pilot test of alkali/polymer (AP) combination flooding was conducted in the west area of the fault block of XingLongTai oil field, which was a fringe water reservoir with a gas-cap. There are 11 wells in the oil-bearing area which is 2.05 km2. The central well group contains 3 injection wells and 1 production well and has an oil-bearing area of 0.037 km2. The injection of a slug of 0.35PV of AP combination solution (2% NaCO3 + 1000 mg/L Polymer (1175A)) was initiated in January 1995 when the oil recovery was 46.75% (OOIP) and the water cut was 96.1% and finished in February 1997 when subsequent water injection was started. Up to August 1998, the average water cut was decreased from 98.0% (prior to AP injection) to 93.5% and the oil recovery was increased by 1.98% (OOIP) for the whole pilot area. The water cut was decreased from 98.0% (prior to AP injection) to 85.6% and the oil recovery was increased by 18.5% for the central well group. Numerical simulation was performed and forecasted using the modified UTCHEM (University of Texas Chemical Flood Simulator). The calculation has shown that AP combination flooding can give a much higher oil recovery than water flooding. The ultimate oil recovery by AP combination flooding for the whole pilot area is 50.1% and 147 tons oil can be produced with one ton polymer. Because the pilot area is of a small scale and the initial invest is larger, the economic benefit is not good enough, but the AP combination flooding does be an effective way to enhance oil recovery after water flooding. It is especially true if the target field is of a larger scale. The influence of alkaline loss on EOR, the effect of AP combination system on sweep efficiency and the causes of formation damage are also studied in this paper.
Field Tests of Polymer Flooding in Relative Homogeneous Thick Reservoir
Authors: xue Jiafeng , Liu Xincang , Yuan Tao , Xu Dianping , Ren Wenhua 
Published: December 2007

Abstract
After the success of polymer flooding field tests in the north of Daqing oil field, commercial applications have been conducting, and remarkable technical and economic results have been obtained. In contrast to north area of oil field, XF has characteristics of low permeability differences, lower heterogeneity, lighter oil, and higher recovery by water flooding. In the late developing period of such high water-bearing layers, in order to study results of polymer flooding, polymer flooding field test has been conducted in the central part of Xing-Five area of south of oil field.
The pilot area is composed of 4 anti-five point well patterns which consists of 4 injectors, 9 producers. The distance between injector and producer is 200m, the total area is 0.31km2. This test be gins in 9,1995, cumulative polymer injection volume has reached 748.8mg/L PV by the end of 2,1999. Central producer in pilot area begins to respond when 128mg/L• PV polymer is injected, water cut drops to the minimum of 46.9%; compared with water cut of water flooding, it has decrease by 49.1%. Up to now, cumulative oil production has reached 2.83×104t, cumulative oil increase is 2.07×104t, that is equivalent to an incremental recovery of 13.6%OOIP.
Performance characteristics of field test differ from the north, which reflects in terms of late producers response in the south, late polymer production, low concentration of producing polymer at the same polymer injection volume. It can mainly attribute to relative weak heterogeneity in oil reservoir, relative uniform propagation of polymer, and enlarged swept volume.
Results of field tests show polymer flooding is economically and technically feasible in the relative homogeneous thick reservoir.
Rheology and Stability of IOR Produced Liquid in Daqing Oilfield
Authors: Di Wu , Guangzhi Ai , Yan Chen , Lihua Han , Sen Lin , Xiangchun Meng , Huicheng Liang 
Published: December 2007

Abstract
Rheology and stability of some polymer flooding and ASP (alkaline, surfactant, polymer) flooding produced liquid were studied in this work. Rheology of the produced water plays an important role in the stability of polymer flooding and ASP flooding produced liquid. The stabilizing effect of residual polyacrylamide in produced water on o/w emulsion depends mainly on its influence on the bulk rheology of produced water, i.e. the viscosity and elasticity modulus of the water phase.
Using New Advances in LWD technology for Geosteering and Geologic Modeling
Authors: Efnik M. S. , Hamawi M. , Al Shamri A. , Madjidi A. , Shade C. 
Published: December 2007

Abstract
In this paper, a Middle East field example is shown to illustrate the application of new advances in Logging While Drilling measurements. In addition to standard two mega-hertz multi-depth resistivity, neutron and gamma ray LWD measurements, azimuthal density and photoelectric factor (Pef) measurements were recorded. The real-time and recorded mode applications of azimuthal density and Pef are discussed in this paper.
Conventional LWD density measurements are circumferentially averaged. This technique will smear the density output at bed boundaries, especially in horizontal wells where the bed's relative angle to the well bore is high. Information from azimuthally acquired quadrant density measurements can be used to clearly detect and evaluate bed boundaries in deviated and horizontal holes. In this paper, it is shown how up and bottom densities are used to accurately locate bed boundaries and other geological features such as faults. For geosteering purposes, up and bottom density displacement was able to show if the bed was being entered from the top or bottom of the well bore. It was also possible to estimate structural dip in real-time.
Sixteen azimuthal density and sixteen azimuthal Pef sectors were recorded in downhole memory. Once these LWD data were retrieved from the BHA memory and image processing and image orientation was done, structural features such as fault, bed boundaries and formation heterogeneities were identified. True dip was computed from the density image. The compilation of this information allowed further evaluation of the geologic model of the carbonate gas-bearing reservoir.