bluuebunny/crossref_metadata_2025_split huggingface dataset:
Numerical Studies of Gas-Hydrates Formation and Decomposition in a Geological Reservoir
Authors: Uddin M. , Coombe D. A. , Law D. A. , Gunter W. D. 
Published: December 2007

Abstract
Gas hydrates are a significant resource of natural gas exist both on-shore buried under the permafrost and off-shore buried under oceanic and deep lake sediments. Recent investigations consider the possibility of sequestering carbon dioxide (CO2), a greenhouse gas (GHG), in gas hydrate reservoirs and at the same time recovering the methane (CH4) from the hydrates. Numerical studies often provide an integrated understanding of the process mechanisms in predicting the potential and economic viability of CH4 gas production and CO2 gas sequestration in a geological reservoir.
This work describes a new unified kinetic model which, when coupled with a compositional thermal reservoir simulator, can simulate the dynamics of CH4 and CO2 hydrates formation and decomposition in a geological formation. The kinetic model contains two mass transfer equations: one formation equation transfers gas and water into hydrate and one decomposition equation transfers hydrate into gas and water. The model structure and parameters were investigated in comparison with a previously published model.
The proposed kinetic model was evaluated in two case studies. Case 1 was a single well natural hydrate reservoir for studying the kinetics of CH4 and CO2 hydrates decomposition and formation. Case 2 was a multi-well reservoir for studying the unified kinetic model to demonstrate the flexibility of CO2 sequestration in a natural hydrate reservoir with potential enhancement of CH4 recovery. A close agreement was achieved between the present numerical simulation and the published results. The model can be applied in the field scale simulation to predict the dynamics of gas hydrates formation and decomposition processes in a geological reservoir.
Mechanism Formations of Corrosion Damage of Inter Equipment in Wells by Continuous Scale-Inhibitor Dosing Utilizing Surface Dosing Systems: Testing Scale and Corrosion Inhibitors
Authors: Daminov A. , Ragulin V. , Voloshin A. 
Published: December 2007

Abstract
At the present time, Rosneft Oil Company is applying various technologies to minimize scaling problem. One of these techniques is, for example, a continuous injection of inhibitors using surface dosing systems to protect downhole equipment from damage caused by scale deposits (more than 1200 wells are equipped with dosimeters). It has been discovered that this method has some disadvantages, in particular an abnormal high rate of downhole equipment corrosion. As a result, wells are destroyed within less than a year. Our estimation shows that for some cases the corrosion rate is higher than 20 mm/year. Corrosion types and mechanisms have been determined. Corrosivity testing of the production from the above wells has been performed using coupons made of the least corrosion resistant material in the injection system, and an industrial adaptation of the material followed the examination. The corrosivity has been studied in a wide temperature and partial pressure CO2 range. Testing and selection of chemicals for corrosion prevention technologies have been carried out.
Predicting Microbially Influenced Corrosion (MIC) in Seawater Injection Systems
Authors: Maxwell S. 
Published: December 2007

Abstract
Many operators have encountered failures due to MIC in seawater injection systems contaminated with sulphate-reducing bacteria (SRB). In some cases, severe pitting and grooves have resulted in flowlines being abandoned or replaced. On the other hand, there are reports of little or no significant MIC in some systems, despite significant contamination with SRB being confirmed. As all the systems are of similar design, transport seawater and employ organic biocide treatments, it may sometimes seem that incidents of MIC are a case of luck rather than judgement.
A qualitative model is presented which predicts when conditions within the system will allow MIC to proceed. The model involves two phases. Firstly a biotic phase which predicts the time required for a sulphide film to develop. Secondly, an abiotic phase which considers three parameters that may stimulate the initiation of MIC pits. The model can be made semi-quantitative by introducing a constant for pitting rate. The ability to predict (even if only qualitatively) the probability of MIC under a given set of circumstances (e.g. different biocide applications, pigging programmes, etc.) during the planning stage of a seawater flood project could significantly improve the development of control strategies.
It is anticipated that the development of such models could allow a corrosion management system to predict and monitor the mitigation of MIC risk. Currently, the use of MIC risk assessment models is not widespread and most MIC monitoring, at best, estimates biocide efficacy only. Whilst biocide efficacy monitoring is an important control, it is not corrosion management.
The model allows for ongoing review of the MIC risk once monitoring data is available.
Optimization of Fracture Length in Gas/Condensate Reservoirs
Authors: Mohan J. , Sharma M. M. , Pope G. A. 
Published: December 2007

Abstract
We present an analytical expression for the optimum fracture length for a gas or gas-condensate well with or without non - Darcy effects in the fracture. It is shown that the optimum fracture length depends mainly on fracture conductivity, formation permeability, size of the condensate bank around the fracture, proppant volume per unit payzone thickness, and reservoir thickness. As the fracture length is increased at a fixed volume of proppant per unit thickness, the well productivity was found to go through a maximum at a particular fracture length. The analytical results are compared with results obtained from fine-grid numerical simulations using a compositional simulator, which are run for sufficiently long periods of time so that pseudo-steady state is reached. The numerical simulation results agree well with the analytical results. The analytical expressions presented can, therefore, be used as a simple method to obtain optimum fracture lengths for gas and gas condensate wells for a wide range of conditions.
Evaluation of the Proppant-Pack Permeability in Fiber-Assisted Hydraulic Fracturing Treatments for Low-Permeability Formations
Authors: Bulova M. N. , Cheremisin A. N. , Nosova K. E. , Lassek J. T. , Willberg D. 
Published: December 2007

Abstract
To achieve maximum production, tight-gas formations require long fractures with contained height growth. This can be achieved by using low viscosity fracturing fluids. Decrease in fluid viscosity typically leads to an increase of proppant settling rate which results in non-uniform proppant placement and reduced effective fracture conductivity. Low-density proppants can offset this effect in low-viscosity fluid, but due to their low strength can be applied only at low closure stresses and relatively low temperatures.
A new fluid system was developed especially for fracturing low-permeability formations (less than 0.01 mD). This system allows for high-strength high-density ceramic proppant to be used with reduced polymer loading and significantly decreased proppant settling rates. All these benefits are the result of adding fibers into a fluid system which create a network, helping to suspend proppant during its transport and placement into a fracture.
Laboratory studies were performed to determine the fiber's influence on long-term proppant-pack permeabilities. Retained conductivities of ceramic and sand proppant packs over the 175-250 0F temperature range were measured under various loadings and closure stress ranges. Testing has shown permeability values of the fiber-laden systems are comparable with the values for fiber-free proppant packs. A parallel study was performed on evaluating proppant settling rates in fiberladen fluids in static conditions. Fiber in a fracturing fluid system reduces the rate of proppant settling by greater than three-fold.
Special attention is paid to a proper proppant selection for hydraulic fracturing. Improper proppant selection can cause significant damage of proppant pack conductivity and minimize benefits of the fluid system.
The results prove that the innovative fiber fluid ensures uniform proppant placement within a long fracture because of fiber presence, provides conductivity comparable to pure proppant pack values, and do not have any limitations at high closure stresses.
Decoupling Damage Mechanisms in Acid-Fractured Gas/Condensate Reservoirs
Authors: Bachman R. C. , Settari A. , Walters D. A. , Rahim Z. , Ahmed M. S. 
Published: December 2007

Abstract
Gas condensate wells within the Khuff C formation in Saudi Arabia are typically acid fracture stimulated following drilling. Early PTA tests conducted after stimulation indicate excellent fracture conductivity and length properties. After tie - in, the wells experience a rapid production loss, which stabilizes after 2 to 5 months. Well producing BHP is below the dew point pressure. This study was undertaken to identify the source of productivity loss. Possible causes include near well liquid dropout, fracture conductivity loss and reservoir permeability loss due to increased effective stresses.
The study was successful in determining the changing total skin with time and allocating it to each of the potential damage mechanisms. This was accomplished by using a reservoir simulation model, which adequately represented stress dependent properties as a simpler function of pressure. A number of type curves were used to assist in making pragmatic decisions as to what parameters to adjust during the history matching process.
Analysis of Gas-Well Reservoir Performance Data Using B-Spline Deconvolution
Authors: Ilk D. , Anderson D. M. , Valko P. P. , Blasingame T. A. 
Published: December 2007

Abstract
This work presents the practical application of the recently developed B-spline based deconvolution methodology to analyze variable-rate/variable pressure drop well performance data from gas wells. As deconvolution provides the corresponding constant rate pressure drawdown response for a well/reservoir system which is affected by variable flowrates, we intend to use deconvolution of production data to identify the reservoir model and perform an analysis for estimating reservoir properties and reservoir volume.
In this work we apply our B-spline based deconvolution methodology to production pressure and flowrate history data (which are typically available on a daily or monthly basis — all field cases in this work (except Case 3) consider daily production data measurements). For this work, we apply our method using traditional gas well test data, as well as regularly measured gas well production data. We also demonstrate the appropriate handling of input data (particularly pressure test data and production data) to ensure stable/accurate deconvolution results.
The application cases in this work should be considered typical for a reservoir or production engineer, and we would expect similar performance/robustness of our methodology as it becomes a common analysis practice.

Objectives
The following objectives are proposed for this work:
To apply and extend the recent B-spline based deconvolution methodology to analyze variable-rate/variable pressure drop gas well performance data. To identify the critical issues which affect the success of deconvolution methodology when applied to production data. To state specific recommendations for practice and/or future work.
Application of a New Fracture-Injection/Falloff Model Accounting for Propagating, Dilated, and Closing Hydraulic Fractures
Authors: Craig D. P. , Blasingame T. A. 
Published: December 2007

Abstract
A new fracture-injection/falloff type-curve analysis method is presented for reservoirs containing slightly compressible and compressible fluids. Type-curve analysis augments conventional before- and after-closure methods, which are also reformulated in terms of adjusted pseudopressure and adjusted pseudotime to account for compressible reservoir fluids. Unlike before- and after-closure methods which only apply to specific (i.e., small) portions of the falloff data, the new type-curve method allows for analyzing all falloff data from the end of the injection through fracture closure, pseudolinear flow, and pseudoradial flow. Similar to conventional well test analysis, a satisfactory interpretation requires comparable and consistent results between the special analysis methods, before- and after-closure, and type-curve analysis.
Evaluation of the Technical and Economic Feasibility of CO2 Sequestration and Enhanced Coalbed-Methane Recovery in Texas Low-Rank Coals
Authors: Hernandez G. A. , Bello R. O. , McVay D. A. , Ayers W. B. , Rushing J. A. , Ruhl S. K. , Hoffmann M. F. , Ramazanova R. I. 
Published: December 2007

Abstract
Carbon dioxide (CO2) from energy consumption is a primary source of anthropogenic greenhouse gas. Injection of CO2 in coalbeds is a plausible method of reducing atmospheric emissions, and it can have the additional benefit of enhancing methane recovery from coal. Most previous studies have evaluated the merits of CO2 disposal in high-rank coals. The objective of this research is to determine the technical and economic feasibility of CO2 sequestration in, and enhanced coalbed methane (ECBM) recovery from, low-rank coals in the Texas Gulf Coast area. Our research included an extensive coal characterization program, deterministic and probabilistic simulation studies, and economic evaluations. We evaluated both CO2 and flue gas injection scenarios.
In this study coal core samples and well transient test data were obtained for characterization of Texas low-rank coals. Simulation studies evaluated the effects of well spacing, injectant fluid composition, injection rate, and dewatering on CO2 sequestration and ECBM recovery.
Probabilistic simulation of 100% CO2 injection in an 80 - acre 5-spot pattern indicate that these coals can store 1.27 to 2.25 Bcf of CO2 with an ECBM recovery of 0.48 to 0.85 Bcf. Simulation results of 50% CO2 - 50% N2 injection in the same 80-acre 5-spot pattern indicate that these coals can store 0.86 to 1.52 Bcf of CO2, with an ECBM recovery of 0.62 to 1.10 Bcf. Simulation results of flue gas injection (87% N2 - 13% CO2) indicate that these same coals can store 0.34 to 0.59 Bcf of CO2 at depths of 6,200 ft, with an ECBM recovery of 0.68 to 1.20 Bcf.
Economic modeling of CO2 sequestration and ECBM recovery for 100% CO2 injection indicates predominately negative economic indicators for the reservoir depths and well spacings investigated, using natural gas prices ranging from $2 to $12 per Mscf and CO2 credits based on carbon market prices ranging from $0.05 to $1.58 per Mscf CO2 ($1.00 to $30.00 per ton CO2). Injection of flue gas (87% N2 - 13% CO2) results in better economic performance than injection of 100% CO2.
Moderate increases in either gas prices or carbon credits could generate attractive economic conditions that, combined with the close proximity of many CO2 point sources near unmineable coalbeds, could generate significant CO2 sequestration and ECBM potential in Texas low-rank coals.
Hybrid Fracture Stimulation in Underpressured Coals
Authors: Ramurthy M. , Lyons B. , Magill D. P. 
Published: December 2007

Abstract
Some of the significant strides made in coal stimulation during the last 25 years can be attributed to the development of new-generation fluid systems (i.e., low gel loading fluids with efficient low-temperature breaker systems that cause less polymer damage in coals). All these new developments were implemented to (a) minimize damage in coals, and (b) maximize production. Water fracture treatments in coals completely eliminated polymer damage but did not always maximize production. The use of new-generation crosslinked fluids did provide better half-lengths and conductivities but still left residual damage in coals. Based on production, it was confirmed that the benefits obtained with this fluid system outweighed the damage created. To further reduce the damage in coals and obtain better regained fracture permeability, implementing hybrid fracture treatments in coals was considered in this San Juan basin project. The term "hybrid" in this case refers to a water pad followed by crosslinked fluid sand stages. Potential benefits of this technique in coals include: (a) minimizing damage caused by gel, (b) maximizing regained permeability, (c) containing height growth, and d) lowering cost.
There are two parts to this work. The first part presented in this paper contains the design, implementation, and encouraging initial results obtained from the seven wells in this project, which is in an underpressured area. This is the first project in which hybrid-type treatments have been applied in a low-pressured formation. This paper will discuss the lessons learned from such an application in coals. When sufficient production data becomes available, the second part of this work will quantify the results via reservoir simulation. The second part will also include quantified results from another current hybrid fracture-stimulation project where the coals are slightly overpressured.
U.K. North Sea and Alaska North Slope: A Comparative Analysis of Petroleum Provinces
Authors: Walker J. A. , Ogbe D. O. , Zhu Tao 
Published: December 2007

Abstract
Alaska's North Slope and the United Kingdom North Sea were petroleum frontiers in the truest sense around 1960 when industry gained access to both areas. Exploration of these two petroleum provinces progressed almost simultaneously with both emerging as significant sources of oil and gas. Both provinces entered the 1960's with no oil production, but, by the end of the 20th century, the provinces combined had delivered almost 50 billion barrels of oil equivalent to markets in Europe and the United States.
Alaska's North Slope started producing oil at about the same time as the United Kingdom North Sea, in the mid to late 1970's. Alaska North Slope (ANS) and UK North Sea oil production rates were approximately equal in 1980, but UK North Sea oil production has exceeded that of the Alaska ANS by more than 40% in recent years. The UK North Sea and ANS share similar areal sizes and other similarities, but differ in several key areas including government policy. This paper examines exploration and development history, resource access, and government take for the ANS and UK North Sea petroleum provinces using information available to the public. This analysis shows that government policies and the lack of a gas market have played a crucial role in the production history of the Alaska North Slope.
Prediction of Slug-to-Annular Flow Pattern Transition (SAT) for Reducing the Risk of Gas Lift Instabilities and Effective Gas/Liquid Transport From Low-Pressure Reservoirs
Authors: Toma P. , Vargas E. , Kuru E. 
Published: December 2007

Abstract
Slug to annular flow pattern transition (SAT) taking place during the upward gas-liquid well transportation is a source of flow instabilities often experienced with conventional gas lifting as well as with unloading operations of water accumulated at the bottom level of gas wells in low-pressure gas or coalbed reservoirs. In order to minimize the pressure drop and gas compression work, gas lifting of relatively large volumes of fluid (oil and water) uses mainly a slug flow pattern while the production of gas with relatively small amounts of condensate or water (unloading operation) uses an annular flow pattern. In both situations, significant decreasing of tubing pressure from perforation to wellhead levels, is associated to significant increase of superficial gas velocity, may induce flow pattern transitions (usually from bubble to slugs and, further from slugs to annular).
This paper uses field data and laboratory measurements to suggest that SAT can be a source of flow instabilities and should be avoided.
Understanding and proper prediction of SAT is particularly essential for developing suitable production operations and for designing effective gas lifting or unloading strategies from low-pressure gas and oil reservoirs (including upward transportation of hot fluids resulting from steam-assisted heavy oil operations).
With depletion of existing gas reservoirs trend the need for effective gas well deliquification is in great demand.
Transportation of water produced at the perforation level (usually between 10-60 m3/d) over a vertical depth of 200 to 2000 m under low (often variable) reservoir pressure (&lt; 50 m of water) ask for finding un-conventional and effective artificial lifting strategies. Improving the understanding of gas-liquid upward transportation mechanisms including the avoidance of instabilities induced by flow pattern transitions is essential.
This paper addresses this problem through laboratory measurements of steady and oscillatory components of flow-pressure under a broad range of gas injected rate and simulated reservoir pressures. Comparison of laboratory data with existing STA models is performed first; selected models are then tested for field situations.
Effective field strategies for avoiding the SAT occurrence using either a slug or an annular flow pattern regime under low-pressure and standard (IPR) reservoir conditions are discussed in view of practical field applications and selection of a suitable gas lifting strategy.
SSC Performance of a Super 13% Cr Martensitic Stainless Steel: Influence of PH2S, pH, and Chloride Content
Authors: Marchebois H. , Leyer J. , Orlans-Joliet B. , Deletombe P. , Langrill C. , De Montleber D. 
Published: December 2007

Abstract
There is an increasing demand for Super 13% Cr (Super Martensitic Stainless Steel) tubing and casing (OCTG – Oil Country Tubular Goods), due to the material's superior strength and CO2 resistance, over conventional 13% Cr steel. Super 13% Cr combines low carbon content with increased Ni and Mo content, and particular heat treatment processes, in order to achieve its superior properties. To date, the literature available on this material is limited, with most articles concentrating on the explanation and remedies to major line-pipe failures that occurred on welds.
This paper summarizes tests to assess the role of chloride content in PH2S and pH testing solution. The negative effect of H2S saturation of the solution was observed, leading to a decrease of the passivation stage of the steel. Taking into account electrochemical parameters such as current densities and corrosion potentials, various environments (pH, chloride content and H2S) where SSC is likely to occur were investigated. The influence of the three parameters led to the creation of a 3-Dimensional mapping of SSC susceptibility with regard to the use of Super 13% Cr Stainless Steels. The Fit-For-Purpose philosophy of the new edition of NACE MR0175/ISO 15156 standard was used to develop this map.