bluuebunny/crossref_metadata_2025_split huggingface dataset:
Analysis of Deposition Mechanism of Mineral Scales Precipitating in the Sandface and Production Strings of Gas-Condensate Wells
Authors: Franco C.A.. A. , Solares J.R.. R. , Al-Marri H.M.. M. , Mukhles A.E.. E. , Ramadhan N.H.. H. , Saihati A.H.. H. 
Published: June 2010

Summary
Thick deposits of various types of mineral scales are presently forming in the tubulars and formation of gas producers drilled in Saudi Arabian carbonate reservoirs. These mineral scales precipitate when ideal thermodynamic conditions combine with dissolved minerals present in formation waters. Without remedial action over time, these deposits can grow thicker and end up plugging tubulars and the reservoir.
Thick deposits of mineral scales have recently begun to appear in gas producers in certain areas of the field. A comprehensive study was conducted to ascertain the nature of the precipitation mechanism and identify potential solutions to the problem. This paper details how laboratory analysis data, well production history, reservoir geology and petrophysics, and reservoir description were analyzed and used with sophisticated computer software to identify the formation-damage mechanism and the different scale types precipitating in the wellbore and formation. Extensive simulation work was conducted as part of the study to forecast the type and amount of mineral-scale precipitation that can be anticipated at varying reservoir and producing conditions. The study also evaluated the most cost-effective and feasible ways to remove different types of scale deposits.
The future scale-inhibition and -removal strategies to be implemented in existing and future gas producers are being derived in large part from the results of the study described in this paper.
Modeling Formation Damage for Flow Simulations at Reservoir Scale
Authors: Ding D.Y.. Y. 
Published: June 2010

Summary
Formation damage generally is limited to the immediate nearwellbore region and needs a particular near-well-flow modeling using fine gridblocks. However, near-well models are usually developed as standalone models and are decoupled from reservoir models. Using a standalone near-well model that does not take into account production scenarios cannot predict well injectivity or productivity correctly.
In this paper, we propose a new technique for the coupled modeling of a near-well-flow model and a reservoir model in a simple and consistent way. In this new approach, data are exchanged and updated through boundary conditions for the near-well model and through numerical productivity indices (PIs) (or skin factors) for the reservoir model. Examples show that this coupled modeling gives quite satisfactory results.
In-Situ Water-Blocking Measurements and Interpretation Related to Fracturing Operations in Tight Gas Reservoirs
Authors: Bazin B.. , Peysson Y.. , Lamy F.. , Martin F.. , Aubry E.. , Chapuis C.. 
Published: June 2010

Summary
Invasion of aqueous drilling, completion, or fracturing fluids can reduce the relative permeability to gas and thereby causes a water block. In the case of low-permeability formations, the capillary pressure tends to be high because of the small pore size. Cleanup of water blocks requires high drawdown unless water vaporization by the flowing gas is improved by using specific additives such as alcohols.
The purpose of this work is to investigate fracture-face damage by measuring relevant petrophysical parameters: absolute-permeability damage and gas return permeabilities. Measurements are performed in representative conditions of a fracturing operation in a tight gas formation: cores with an absolute permeability of 10 μd set at Swi and experimental pressure of 200 bars for the fracturing-fluid invasion. Water and gas saturations during the fracturing-fluid invasion and during gas backflow are monitored by X-ray equipment. Adding alcohol in the fracturing fluid has a striking effect on resolving water blocks. Cake formation on the simulated fracture face is also discussed.
Numerical simulations are performed to assess relative permeabilities from the experimental results. It is shown that hysteresis of gas and water relative permeabilities has a strong impact on the rate of water removal. Sufficiently high pressure drawdown is crucial to overcome capillary forces and initiate the alcohol- assisted vaporization process. Water removal by water vaporization is assessed and compared to the experimental results.
Effect of Salinity on Wettability Alteration to Intermediate Gas-Wetting
Authors: Wu Stanley , Firoozabadi Abbas 
Published: June 2010

Summary
The effect of salinity on the alteration of wettability from waterwetting to intermediate gas-wetting is studied in this work. We find that NaCl salinity increases water-wetting when a core is saturated with brine. NaCl also reduces gas absolute permeability, as reported in the literature. CaCl2 salinity effect is dramatically different from that of NaCl brine and has a minor effect on permeability. The NaCl, KCl, and CaCl2 brines have an adverse effect on wettability alteration. To alleviate the effect of salt on chemical treatment, we suggest pretreatment by displacement of brine with water and subsequent drainage by nitrogen.
Spectral and Cycle-Counting Fatigue Damage Estimation Methods for Steel Catenary Risers
Authors: Power T. L. , Maniar D. R. , Garrett D. L. , Phifer E. H. , Vogiatzis J. P. 
Published: June 2010

Summary
Estimating fatigue damage under wind-driven sea loading is of primary importance in the design of steel catenary risers (SCRs) serving floating hosts. For design, the wind-driven sea is modeled as a stationary random process. The resulting dynamic stress in the SCR is also a stationary random process. Spectral methods provide closed-form fatigue damage estimates in terms of statistics for stationary random stress processes. Cycle-counting methods, such as rainflow cycle counting, provide an alternative damage estimation approach that is generally applicable and requires simulation of stress time series. The cycle-counting approach requires more computation than spectral methods. Damage estimates using the cycle-counting method may be lower than spectral damage estimates; however, a substantial amount of simulation may be required to quantify the difference.
This paper considers fatigue damage in SCRs attached to both tension-leg platform and semisubmersible hosts. Spectral and cycle-counting estimates are generated and compared. Accuracy of the estimates is discussed, and guidelines for damage estimation are presented. It is demonstrated that the differences between spectral and cycle-counting estimates of lifetime fatigue damage arise primarily from assumptions made regarding the spectral shape of the stress processes of interest.
Chromatographic Partitioning of H2S and CO2 in Acid Gas Disposal
Authors: Pooladi-Darvish M. , Hong H. , Stocker R.K. , Bennion B. , Theys S. , Bachu S. 
Published: June 2010

Abstract
Hydrogen sulfide breakthrough in producing wells occurred after the breakthrough of CO2 in the Long Coulee Glauconite F reservoir in southern Alberta, where acid gas (98% CO2, 2% H2S) has been injected since 2002. It was hypothesized that the preferential solubility of H2S in formation brine is responsible for the delay in H2S breakthrough.
To study the chromatographic separation of H2S and CO2, a series of experiments were conducted to measure the solubility of CO2 and H2S in formation brine at in-situ conditions. Immiscible displacement experiments were performed in a slim tube packed with silica sand to study the breakthrough behaviour of different gas components. The experiments were then modelled using a compositional simulator, and the effect of different factors on the delayed breakthrough of H2S was examined using a series of sensitivity studies.
It was confirmed that the preferential solubility of H2S over CO2 leads to it being stripped off at the leading edge of the gas displacement front, resulting in its delayed breakthrough. A similar delay in H2S breakthrough occurs even at higher H2S concentrations (e.g. 30%) in the injected gas. Through the simulation studies it was shown that the delay in H2S breakthrough becomes more pronounced if the gas front is more diffusive. For example, it was shown that, when gravity forces or mobility ratio favour stable displacement, CO2 and H2S breakthroughs occur closer to each other.
This is of significance, particularly for monitoring of impure CO2 storage in deep saline aquifers, where the impurity may consist of H2S. Detection of CO2 at a monitoring well would indicate that the more noxious H2S is likely to show up after some time lag. This paper describes the experiments and the simulation studies and presents the implications of the chromatographic partitioning of H2S and CO2 for geological storage of acid gas or impure CO2.
Study and Application of Gelled Foam for In-Depth Water Shutoff in a Fractured Oil Reservoir
Authors: Qing Y. , Yefei W. , Wei Z. , Ziyuan Q. , Fulin Z. 
Published: June 2010

Abstract
A gelled foam is comprised of water, a foaming agent (surfactant), a foaming stabilizer (polymer) and a cross-linking agent. This system with gel as the outer phase is more stable than conventional foam that uses water as the outer phase. Therefore, the gelled foam system prolongs the effective period of water shutoff. By using the Ross Foamer Device to determine its foaming and stability characters, we verify that the best foaming agent is 0.3% YG240; the stable foam agent is 0.2- 0.4% HPAM; the cross-linking agent is 0.09% sodium dichromate and 0.16% sodium sulphite and nitrogen. On the basis of bench-scale evaluations of characters on gelation time and water shutoff efficiency, the pilot test is performed on Well H1340 in the Huoshaoshan fractured reservoir. The workover program includes washing the larger fissures using a highly efficient oil displacement agent, injecting gelled foaming agent, over-displacing fluids, nitrogen and water, then shutting in the well for hardening. Field tests show that good blocking efficiency is gained in the well with a water cut decrease of 20 - 50% and oil production increase of 3.7 - 11.0 m3/day.

Introduction
At present, most oil fields in china are in a high water cut period; injection water and edge water usually breakthrough into oil wells along high permeability zones, causing oil well productivity to decline and development results of waterflooding to get worse. As conventional water shutoff techniques such as mechanical shutoff and chemical shutoff in high permeability zones associating with limited shutoff diameters and depth, the plugging effects decreased rapidly and oil recovery from waterflooding has been greatly affected. In recent years, field tests of profile control with foam have been developed, yet high permeability zones can not be plugged effectively because of a short half life and the limited blocking radius of foam agents. Thus, it is necessary to study the techniques of gelled foam for in-depth water shutoff.
The Velocity and Shape of Convected Elongated Liquid Drops in Vertical Narrow Gaps
Authors: Shad S. , Salarieh M. , Maini B.B. , Gates I.D. 
Published: June 2010

Abstract
The motion and shape of a liquid drop through another continuous liquid phase (conveying phase) in a vertical Hele-Shaw cell with two different apertures were investigated experimentally. Two different liquid/liquid systems were tested. In all cases, the continuous phase was more viscous and wetted the bounding walls. In the capillarity-dominated region, the irregular shape of the discontinuous phase changed with time and distance, with much lower velocity than that of the conveying phase. In contrast to gas/liquid systems, the velocity of these stabilized, elongated drops was 2.5 to almost 5 times higher than that of conveying liquid. Despite the similarities between flow in vertical and horizontal Hele-Shaw cells, the velocity of droplets in a vertical fracture is different from that of a horizontal fracture. A new correlation is derived from dimensionless analysis and the experimental data to predict the elongated drop velocity as a function of the dimensionless parameters governing the system.

Introduction
Two-phase flow in micro-fractures is fundamental to many different fields of advanced science and technology, such as chemical process engineering, bioengineering, medical and genetic engineering, as well as petroleum engineering. For instance, understanding the flow of two-phase fluids in near-parallel gaps through fractured rocks has a significant effect on design of different recovery methods for naturally fractured reservoir.
The flow pattern of two-phase immiscible flow in a fracture depends on the flow rates of the phases, the geometry, aperture, roughness of the fracture, the flow properties of the phases and interfacial tension between the phases. The flow patterns in a fracture are different from that in macro-sized rectangular ducts or pipes because of the small aperture, which can enhance capillary effects. The flow structure in the fracture affects the flow and transport through the surrounding porous matrix blocks. The slug flow pattern in a fracture, which occurs over a wide range of parameters, is frequently encountered in oil-wet fractured reservoirs during the immiscible displacement of viscous oil. It also occurs in natural gas reservoirs during displacement of water during gas production.
CO2 Flooding Potential in West-Central Alberta: Generalized BusinessCase of a Medicine River/Gilby Area Mature Waterflooded Reservoir
Authors: Singhal Ashok K. 
Published: June 2010

Abstract
There are several maturing waterfloods in the Medicine River/Gilby region of West-Central Alberta which are operating at high reservoir pressures, and are suitable candidates for enhanced oil recovery (EOR) by CO2 flooding. Potential CO2 supplies also exist in the region from various petrochemical, as well as sour gas and solution gas processing plants. A prototype reservoir was selected for a detailed "business case" study. CO2 flooding and geological storage were seen to be feasible in the prototype reservoir based on geological/ reservoir reviews, laboratory testing and reservoir simulation.
Economic parameters (payout periods for the investment, rates of return) on risk-weighted basis were moderate in light of front-end capital requirements for extraction, recycle and transportation facilities. The situation would change for the better if regional infrastructure for CO2 capture, extraction and transport is developed. This, in turn, is dependent upon adequate assured demand. On the other hand, demand won't develop unless there is appropriate infrastructure in-place. Fragmented ownership of the resource and of CO2-rich waste gas streams, as well as inertia favouring status quo, are some of the other challenges.
We present here a generalized "business case" for illustrating some of the issues of CO2-EOR implementation.

Introduction
CO2-EOR is receiving increasing attention mainly because of the following emerging trends:Increasing awareness of potential reserves addition by CO2 flooding in mature sedimentary basins such as the Western Canadian Sedimentary Basin (WCSB), based on performance of Weyburn and Joffre Viking CO2 flooding projects in WCSB, and also in various oil fields of West Texas Permian Basin.Growing recognition of the importance of Carbon Capture and Storage (CCS) and anticipated incentives for CCS projects in value-added mode such as EOR.Consensus that the main barrier to widespread implementation of CO2-EOR in Alberta is lack of supply and transportation infrastructure for CO2.
Cyclic Stiffness Degradation in Nonlinear Jackup Dynamics
Authors: Dean E.T.R.. T.R. , Metters R.. 
Published: June 2010

SummarySNAME (2002) gives equations to describe degradation of foundation stiffness for jackup spudcans, depending on the size of a load cycle within a yield envelope. Using these and other proposals, this paper develops a simplified dynamic analysis of jackup cyclic response. Under static conditions, a lower-bound collapse load for a pinned foundation can be larger than for an encastré assumption. Under dynamic conditions, important nonlinearity because of stiffness degradation is confirmed. Chaotic dynamic responses may be possible.
Potential Benefits of Data Integration for Pipeline Integrity Management Programs
Authors: Fehr D. 
Published: June 2010

Abstract
Pipeline integrity management programs are a requirement under Annex N of CSA Z662.07. Annex N requires that data from many sources and details be collected, integrated and analyzed on a continuous basis. The stated goal is to provide guidance for developing, documenting and implementing pipeline integrity management programs, which provide safe, environmentally responsible and reliable service(1). If executed properly, there should be improved pipeline integrity with measurable improvements and benefits. An important step in reaching this goal is risk assessment, which requires continuous data input to maintain valid integrity assessments. This dynamic process of data collection and integration enables continuous analysis and potentially leads to a more proactive integrity management system.
The biggest problem for most operating companies in creating a dynamic and proactive integrity management program (IMP), compliant with Annex N, is in handling the significant data issues. Indeed, the data collection, integration and analysis are the most daunting tasks of the program. A software solution that accepts data from the many activities involved in the lifecycle of a pipeline system would be potentially beneficial. Application of integrated software tools in the oil and gas industry will result in improved integrity management, greater confidence in our pipeline infrastructure and economic benefits.
We will review some of the data requirements of Annex N of CSA Z662.07 and identify the components of the program that may differ from your existing management plan. The nature and detail of data to be managed will be presented. Finally, we will provide an example of the role that software tools can play to assist in meeting the requirements of this challenging regulatory initiative.
Optimization of Large Gas Pipeline Network--A Case Study in China
Authors: Jin Lu , Wojtanowicz Andrew K. 
Published: June 2010

Abstract
In China, annual natural gas consumption is over 67 billion cubic meters with an expected growth rate of 10% per year. Most of the gas is transported from well heads to markets over cross-country gas networks, which requires construction of the West to East Gas Network--one of the largest gas networks in the world. Presently, the network is comprised of four large-diameter pipelines and will include most major gas pipelines in China in the future. The network distributes approximately 30 x 109 m3 gas per year, of which 3% to 5% is burned to power the gas transportation. At current gas prices, gas transportation costs are roughly 350 million per year, which is a considerable cost that could be reduced by improvements in network design and operation.
This paper reports on a study aimed at optimizing the network to minimize its energy consumption and cost. The large size and complex geometry of the network required breaking the study down into simple components, optimizing operation of the components locally, re-combining the optimized components into the network and optimizing the network globally. This four-step approach employed four different optimization methods, penalty function method, pattern search, enumeration and non-sequential dynamic programming, to solve the problem. The results show that cost savings, because of global optimization, are reduced with increased throughput. For example, increasing the gas rate from 67 - 90 million m3/d would reduce operational cost savings because of optimization from 23% - 1.15%. Moreover, the study shows that if the compressors were fully loaded at their maximum rating, the optimized operation would approach the one being presently practiced. Thus, the optimization is effective and much needed when the system does not work at its maximum capacity, a typical case in the present operations of Chinese gas networks.
Estimation of Steam Chamber Extent Using 4D Seismic
Authors: Tanaka Motonao , Endo Kenji , Onozuka Shigenobu 
Published: June 2010

Summary
The Steam-Assisted Gravity Drainage (SAGD) process has been successfully implemented to produce ultra-viscous bitumen from the Athabasca oil sands in the province of Alberta. In the Hangingstone area, 15 pairs of SAGD wells had been drilled in the reservoir by 2006, each a maximum of 30 m in thickness and approximately 300 m in depth. The production reached an average of 8,000 BOPD in recent years. The reservoir is geologically characterized as a stacked incised valley with fills in fluvial to upper-estuarine channels. Thin mudstone layers and abrupt changes in facies caused by sedimentary deposits present complexities and difficulties for SAGD implementation.
A 3D seismic survey was conducted in 2002 to obtain a clear view of geology that was fully utilized for planning additional wells. In order to evaluate SAGD efficiency and performance, a time-lapse 3D seismic survey was carried out in 2006. In this paper, P-wave velocity (Vp) maps, transformed from the seismic travel-time maps, were interpreted with a new methodology for evaluating the areal extent of the steam chamber zone created by the SAGD process. In the previous experimental study of seismic velocity measurements with oil sands cores, Vp was found to steeply drop with an increase in temperature and to gently decrease with an increase in pore-pressure.
Based on the experimental results, a petrophysical model was formulated to express Vp as a function of temperature, pressure and water saturation. The high-pressure and high-temperature zone of the SAGD process should generate differences between the first (2002) and second (2006) Vp maps from which we can estimate the area of the reduced bitumen viscosity with a temperature increase. As effects of pressure are probably more areally extensive than effects of temperature, these two effects on the Vp maps need to be segregated. As a new method, a scaling factor for the Vp reduction was first estimated to adjust the laboratory-scale and field-scale. We then calculated a distribution of Vp reduction corresponding to steam chamber conditions in order to decouple composite effects of temperature and pressure, based on the petrophysical model. Distinguishing the high-temperature and high pore-pressure zone from the low-temperature and high pore-pressure zone, we could determine a steam chamber distribution.
The bitumen volume in the steam chamber zone was estimated and compared with the actual production. The methodology, interpretation procedures and results obtained are presented in detail.