bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Dynamic Simulation Study of Water Hammer for Offshore Injection Wells to Provide Operation Guidelines
Authors: Tang Yula , Ouyang Liang-Biao 
Published: July 2010

Abstract
In water injectors, rapid shut-in creates a water hammer effect. Over time, injectors that undergo repeated rapid shut-ins often have significantly reduced injectivity and show evidence of sanding and even failure of the down-hole completion. This study is to provide an operational reference for the well injection for an offshore deepwater field to mitigate back-flow and maintain the downhole sand-control device integrity and thus satisfactory water-injectivity.
Two different shut-in scenarios have been investigated. One of the scenarios is that among the three water injection wells, two are shut-in and the third one is kept open. Another scenario is that the top side pump is stopped while the three injection wells are still kept open. Water hammer sensitivity on different parameters, such as valve installation position, stroke time, water back flow conditions and the hydraulic characteristics, has been performed.
For Scenario I, the pressure change due to wellhead shutting-in is around 200 psi at bottomhole (BH), which is much lower than the amplitude seen at the wellhead (3400 psi). The third well which stays open for injection experiences even larger pressure surge (around 450 psi at bottomhole). Back flow for the opening well could be close to 10,000 stb/d. With increasing skin due to cumulative injectivity damage by water particles plugging and/or thermal induced fracture closure at shut-in, the water hammer pressure fluctuation can be as high as 1200 psi.
For Scenario II, pressure fluctuation due to top side shut-in is 300 psi. With SCSSV closing when back flow is felt, the water hammer fluctuation can be reduced to around 200 psi.
Unlike the classic water hammer in the pipeline, water hammer in the water injection wells is much less in terms of surge amplitude, as the high injectivity reservoir behaves like a cushion to absorb the water hammer impact on downhole completion and sand-control infrastructure. Water hammer in the wells and pipeline system experiences: (1) after-flow with reduced BHP and flow rate into formation; (2) back flow when BHP becomes less than reservoir pressure; (3) water flows into reservoir again when BHP starts to increase. This cyclic process continues with reduced amplitude in each cycle due to friction.
Results also show that check valve set at the bottomhole could stop the back flow in less than 1 sec.
This study provides useful reference and operation guidelines on offshore water injection and completion design consideration.
Development and Sustainability of a Small Gas Based Economy
Authors: Boodoo Craig 
Published: July 2010

Abstract
Trinidad and Tobago has become a major player in the export of natural gas and gas related products over the past decade. This reflected a deliberate policy change within Trinidad and Tobago. It involved significant investment in people, technology and infrastructure and has enabled us to exploit several niche as well as some conventional markets that were previously inaccessible. Our markets have expanded from the Caribbean and North America to Europe, Asia, the Orient and Latin America.
This paper discusses some of the steps taken towards developing a small gas based economy and ensuring its sustainability.
We will briefly discuss
The major gas based industries that have been developed; which include Liquefied Natural Gas (LNG), Methanol and Ammonia Production growth from insignificant to world class; in terms of natural gas as well as in the previously mentioned industries Reserves fluctuations; how they are perceived and what does it mean in terms of sustainability Growth of the economy; from a national budget of under 12 billion US dollars to over 50 billion in less than 10 years What is being done to encourage sustainability
The Trinidad model is currently being considered by other states and this paper could help in their decision process.
Layering and Oil Recovery: The Impact of Permeability Contrast, Gravity, Viscosity and Dispersion
Authors: Tungdumrongsub Suphawan , Muggeridge Ann 
Published: July 2010

Abstract
The vertical sweep efficiency of all secondary and tertiary oil recovery processes will be affected by the viscosity and density contrast between the oil and the displacing fluid as well as the existence of layers in the reservoir and the permeability contrast between those layers. Mixing between injected and reservoir fluids driven by physical dispersion will alter the effect of these factors on some enhanced oil recovery processes such as miscible gas injection or low salinity water injection. If physical dispersion is large enough it may result in vertical sweep efficiencies close to 100% but will thereby reduce the microscopic sweep efficiency of the EOR process.
This paper investigates the impact of variations in permeability contrast, gravity, viscosity, and dispersion on the oil recovery from a first-contact miscible gas injection scheme in a two layered reservoir. The variations are characterized in terms of mobility ratio, viscous to gravity ratio, layer permeability contrast, vertical to horizontal permeability ratio and the transverse dispersion number proposed by Lake and Hirasaki (1981). The reservoir behaviour is quantified at early and late time in terms of breakthrough time, oil recovery at 1 PVI and late time and solvent cut.
Overall, dispersion dominates oil recovery when the transverse dispersion number is greater than one regardless of mobility ratio, layer permeability contrast or viscous to gravity ratio. The transverse dispersion number can be used to evaluate the impact of cross-layer mixing on vertical sweep for a far wider range of flow regimes than originally investigated by Lake and Hirasaki (1981). This work demonstrates that the transverse dispersion number can and should be used to assess whether vertical or microscopic sweep efficiency will be dominant in any displacements where dispersion may have an impact on recovery.
Static and Dynamic Estimates of CO2 Storage Capacity in Two Saline Formations in the UK
Authors: Jin Min , Pickup Gillian , Mackay Eric , Todd Adrian , Monaghan Alison , Naylor Mark 
Published: July 2010

Abstract
Estimation of CO2 storage capacity is a key step in the appraisal of CO2 storage sites. Different calculation methods may lead to widely diverging values. The compressibility method is a commonly used static method for estimating storage capacity of saline aquifers: it is simple, easy to use and requires a minimum of input data. Alternatively, a numerical reservoir simulation provides a dynamic method which includes Darcy flow calculations. More input data are required for dynamic simulation, and it is more computationally intensive, but it takes into account migration pathways and dissolution effects, so is generally more accurate and more useful. For example, the CO2 migration plume may be used to identify appropriate monitoring techniques.
Two typical saline aquifer storage sites were analysed using both static and dynamic methods. One site has a comparatively simple geology, while the other has a more complex geology. For each site both static and dynamic capacity calculations were performed. CO2 injection for 15 years was followed by a closure period lasting thousands of years. The proportion of dissolved CO2 and the proportion immobilised by pore scale trapping were calculated.
The results of both geological systems show that the migration of CO2 is strongly influenced by the local topography of the upper surface of the aquifer formation. The calculated storage efficiency for the first site varied between 0.5% and 1% of total pore volume, depending on whether the systems boundaries were considered open or closed. Simulation of the deeper, more complex geological system gave storage capacities as high as 2.75%.
This work is part of the CASSEM (CO2 Aquifer Storage Site Evaluation and Monitoring) integrated study to derive methodologies for assessment of CO2 storage in saline formations. Although, static estimates are useful for initial assessment, we demonstrate the value of performing dynamic storage calculations, and the opportunities to identify mechanisms for optimising the storage capacity.
Experimental Research of work of Different ESP Stages on the Viscous Fluids
Authors: Mokhov Mikhail , Tsunevskiy Andrey 
Published: July 2010

Abstract
Recent years there is trend of oil production increase from the wells with abnormal operating conditions. One of the complicated factors is elevated viscosity of the oil well production. Selection of the high-performance equipment for the work in such conditions is nowadays very relevant. The purpose of this research is a comparison of work of different construction ESP stages on the viscous fluids.
Tests of work of Different ESP Stages were hold on the experimental bedstead of Oil Field Development and Exploitation Department of Gubkin University. Tested ESP Sections are shown in Figure 1.
The following ESP stages were used as a subject for comparison: production stage VNN5-125, production stage VNN5-125 with bored impeller blades, and new construction stage with open-type impeller, which was developed at the Oil Field Development and Exploitation Department of Gubkin University.
Iterative History Matching Technique for Estimating Reservoir Parameters from Seismic Data
Authors: de Souza R. M. , Machado A. F. , Munerato F. P. , Schiozer D. J. 
Published: July 2010

Abstract
High uncertainties associated with unknown fluids and pressure distributions could hamper the history matching process. Accordingly, efforts have been made to evaluate these properties distributions from static and dynamic seismic attributes. Nevertheless, these new methodologies aim to develop quantitatively seismic data integration, which require a suitable association between Petro-Elastic and Flux Models parameters dealing with the inherent inter-dependence between simulation and rock physics parameters.
In this paper it is presented an iterative workflow between two optimization processes. Firstly, a coupling between a Petro-Elastic Model and a reservoir simulator provides Acoustic Impedance (AI) values for two numerical models that have to be matched. The one that has to be honored provides the synthetic "observed" AI data and the other gives the calculated AI values. An objective function based on these is minimized through a Pre-Conditioned Conjugate-Gradient method under reservoir simulation constraints, in order to achieve saturation and pressure trends.
As a second step, a history matching procedure where the saturation/pressure values derived from the former one are now the models to be honored. Then, this information is combined with flux lines in the parameterization phase delineating reservoir heterogeneities to define regions where permeability objective functions are optimized. The saturation/pressure trends, evaluated by this last step, are used to update the initial inputs at the first one, providing history matching constraints to the overall processes.
This technique allowed to determine faults and permeability channels with less uncertainties and higher accuracy and decreasing in time-consuming of the history matching procedure was obtained. Moreover, this methodology improved the reservoir behavior predictions reliability, through quantitative seismic data integration in the history matching process.
Certainly the major goals are the integration aspects of this proposed methodology combined with the obtained improvements in the history matching process.
Experimental Research of Work of Different ESP Stages on the Viscous Fluids
Authors: Mokhov Mikhail , Tsunevskiy Andrey 
Published: July 2010

Abstract
Recent years there is trend of oil production increase from the wells with abnormal operating conditions. One of the complicated factors is elevated viscosity of the oil well production. Selection of the high-performance equipment for the work in such conditions is nowadays very relevant. The purpose of this research is a comparison of work of different construction ESP stages on the viscous fluids.
Tests of work of Different ESP Stages were hold on the experimental bedstead of Oil Field Development and Exploitation Department of Gubkin University. Tested ESP Sections are shown in Figure 1.
The following ESP stages were used as a subject for comparison: production stage VNN5-125, production stage VNN5-125 with bored impeller blades, and new construction stage with open-type impeller, which was developed at the Oil Field Development and Exploitation Department of Gubkin University.
Application of Integrated Production and Reservoir Modeling to Optimize Deepwater Development
Authors: Stoisits R. F. , Bashagour H. M. , Su C. G. 
Published: July 2010

Abstract
A deepwater satellite field project encompasses two fields which are in the general vicinity of two existing Floating Production Storage and Offloading (FPSO) vessels. A number of development architectures that include various subsea tie-backs to two existing FPSOs and, in some cases, an additional FPSO were potential candidates for development. To accelerate the project schedule, Reservoir and Subsea, Umbilicals, Risers, and Flowlines (SURF) Engineering were conducted in parallel. In order to establish an optimal SURF architecture, a method to forecast production behavior of the various architectures is required. To achieve this objective, an Integrated Production Modeling (IPM) tool was developed. Components of this tool model reservoir material balance, well, flowline, riser, and facility performance throughout the project life. Flow assurance analysis, project planning, evaluation, and optimization are facilitated by this model. IPM achieves these objectives by enabling rapid generation of production forecasts consistent with available field information while honoring hydraulic and capacity constraints. When an optimal SURF architecture was developed, system operability was assessed by applying transient flowline and riser analysis to the production system. System operability requires that the SURF architecture is viable over a range of operating conditions spanning upside and turndown scenarios. Upon completion of the rigorous reservoir models, rate profiles were generated by reservoir simulation and compared to the range of rates used to develop the SURF architecture. The reservoir simulation rate profile was contained within the operating range used to develop the SURF architecture. Application of IPM resulted in an optimal SURF architecture, which was developed in parallel with the rigorous reservoir models. The parallel engineering effort allowed an extensive investigation of SURF architectures while accelerating the project schedule.
An Effective Stimulation Fluid for Deep Carbonate Reservoirs: A Core Flood Study
Authors: Mahmoud M. A. , Nasr-El-Din H. A. , De Wolf C. A. , LePage J. N. 
Published: July 2010

Abstract
Matrix acidizing is used to remove near wellbore damage and create channels or wormholes in carbonate formations to improve well performance. The use of conventional matrix acidizing fluids with HCl is not effective in some cases because of the rapid acid spending. Previous studies have demonstrated the use of chelates such as ethylenediaminetetraacetic acid (EDTA) and N-hydroxyethylenediaminetriacetic acid (HEDTA) as alternatives for HCl to stimulate carbonate reservoirs.
A recently introduced chelating agent was examined to stimulate deep carbonate reservoirs. This chelating agent can be used at very low injection rates to avoid fracturing the target zone during the treatment, which may occur if HCl is used at high flow rates. The chelating agent used in this study was glutamic acid-N, N-diacetic acid (GLDA). Two sets of calcium carbonate cores were used one with 1.5 in. diameter and 20 in. length and the other set was 1.5 in. diameter and 6 in. length. Calcium carbonate cores such as Indiana limestone cores were used in this study. A dolomite core 1.5 in. diameter and 6 in. length was used to investigate the ability of this chelating agent to stimulate dolomite cores. The cores were treated with GLDA at various pH (1.7–13) and temperatures (180–300°F). The concentrations of dissolved calcium, magnesium, and GLDA in the core effluent were measured for material balance determination.
GLDA was found to be highly effective in creating wormholes over a wide range of pH (1.7–13) in calcite cores. Increasing temperature enhanced the reaction rate, more calcite was dissolved, and larger wormholes were formed for different pH with smaller volumes of GLDA solutions. In addition, GLDA was very effective in creating wormholes in the dolomite core as it is a good chelate for magnesium. GLDA was found to be equally effective in creating wormholes in short and long cores.
History-Matching With Sensitivity-Based Parameter Modifications at Grid-Block Level
Authors: Almuallim H. , Edwards K. , Ganzer L. 
Published: July 2010

Abstract
Traditionally, history-matching has been a trial-and-error process, where various model parameters are repeatedly adjusted over successive simulation runs so that the difference, or mismatch, between simulated and observed values is minimized. In general, the relationship between such mismatch and the values of the parameters is quite complex. A great deal of expertise is required to figure out patterns that capture such relationship intuitively. Moreover, the number of parameters is so immense that the engineer has to restrict the attention to a small set of parameters, possibly missing influential ones.
In this work, we rigorously compute the derivatives of the mismatch with respect to each parameter, taking advantage of all pieces of simulator outputs, as well as our detailed knowledge of the fluid flow equations implemented within the reservoir fluid-flow simulator. With this new approach, a single simulation run followed by a derivatives calculation session is sufficient to detect how each parameter affects the mismatch, and hence, to decide how (or whether) to change each parameter to improve the match.
This approach has been successfully applied to history-match a three-phase case of a reservoir in North America with 45 years of production history and more than 40 wells. We started from a case that has already been matched through conventional means. We show that, based on our technique, very significant improvements can be achieved beyond the point where conventional means have been exhausted using only a small number of simulation runs.
Experimental and Numerical Calculation of Polymer Base Mud without Solids Invasion in a Porous Media
Authors: Moreno R. B. , Bonet E. J. 
Published: July 2010

Abstract
The present paper intends to compare experimental and simulation results for polymer based flow through porous media. An innovative experimental study, including injection experiments and CT scanning evaluation (X-Ray/2D), was carried out to investigate the characteristics of filtrate invasion.
Normally the drilling mud includes solid particles to minimize mud filtrate invasion, however some authors emphasizes the use of drill-in fluids solid free to minimize irreversible damage due to pore plugging by mud's particles. Moreover, peculiar non-Newtonian behavior of polymers has been pointed out as possible solutions to these problems.
For these reasons, we performed experimental and numerical calculation of polymer base mud invasion in a porous media without bridging agents. We are presenting the results of 24 tests and studying in detail one of various experimental runs. Calculated data and laboratory measured data were compared with drilling fluid invasion's process.
Invasion depth, contact time and saturation profiles were carefully analyzed. The CT scan images were very helpful to inform the pattern invasion: stabilized or fingering invasion. The information is very helpful to program adequate drilling mud.
Novel Analytical Methods of Temperature Interpretation in Horizontal Wells
Authors: Muradov K. M. , Davies D. R. 
Published: July 2010

Abstract
Long (horizontal) completion intervals typically show a wide variation in the inflow distribution along their length due to either formation heterogeneity or (frictional) flow pressure losses. Monitoring of the inflow profiles in such wells is an important step in efficient reservoir management. Accurate temperature measurements (using distributed temperature sensors, permanent downhole gauges or other forms of production logging) have become more widely available in recent years. Many published papers describe temperature sensing and its phenomenological interpretation; but few attempts have been made recently to develop a comprehensive mathematical basis for the analysis of downhole temperature behaviour.
This paper presents a holistic, analytical, mathematical model for calculation of the temperature profile in horizontal wells producing liquids for reservoirs where thermal recovery methods are not being employed. The model presented in this paper rigorously accounts for (1) the Joule-Thomson effect, (2) convection, (3) transient fluid expansion and (4) time-dependent heat loss to the surrounding layers.
A synthetic horizontal well model has been built using a commercial, scientific simulator as a test-bed to provide the data to allow a rigorous evaluation of the efficacy of our novel analytical methods. Asymptotic, analytical solutions have also been found for transient and steady-state flow. It has also been found possible, in addition to these constant flow rate solutions, to apply the well known pressure analysis solution techniques for the estimation of (1) thermal properties and (2) inflow profiling.
The methods proposed here can be applied to a wide variety of well completion types, flow conditions and system properties. They form the basis for the calculation of oil and water flow phase cuts and distributions based purely on temperature measurements. Their use will further increase the potential applications of the modern downhole monitoring and control capabilities currently being installed in wells. As such, they will form an essential element of the "digital oil field".
Hydrocarbonate Reservoir Characterization Constrained to Seismic Attributes
Authors: Guillou Olivier , Schiozer Denis José , Biver Pierre 
Published: July 2010

Abstract
The growing difficulties encountered in petroleum exploration and production, such as declining discoveries, increasing coastal distances and field depth, create a constant need for innovation. To improve the knowledge and dominate reservoirs located in remote areas, new tools and methodologies must be developed. With the steady increase in computing power and the birth of new algorithms, this demand can be satisfied and project risks can be reduced.
From new seismic attributes integration methodologies developed into an optimization process based on forward modeling, different valid results have been obtained. In this context, seismic constraint characterization has revealed an effective way to improve the seismic quality and the relevance of generated models (Barens et al, 2004).
This paper proposes to compare the results of three geological modeling methodologies and its impact on a field development risk analysis. The case study is realized on a deep offshore West African turbidite with a relevant exploration wells number and a good 3D seismic survey quality.