bluuebunny/crossref_metadata_2025_split huggingface dataset:
Analytical Solution for Transient Temperature Field Around a Cased and Cemented Wellbore
Authors: Mendes R. B. , Coelho L. C. , Guigon J. , Cunha G. G. , King V. P. S. , Landau L. 
Published: December 2007

Abstract
Thermal recovery techniques have been widely used to enhance production in heavy oil reservoirs. The high temperatures increase the fluid mobility. The thermal stresses generated by high temperature changes may cause material damage, such as collapse, buckling or shear failure of the casing and hydraulic sealing loss of the cement sheath due to its cracking.High temperatures in open-hole completions may lead to grain shearing or cracking, increasing effective borehole radius.The evaluation of the stress state induced by temperature changes is of major interest in oil wellbore drilling and exploitation.
The temperature field around the well is usually evaluated by numerical techniques such as the finite difference method or analytically through Laplace transform, assuming a constant temperature at the borehole wall.The method proposed herein considers the radial heat conduction through the bore-face.Multilayer cylindrical of heterogeneous materials in perfect thermal contact and with constant physical properties composes the geometry of the problem. The heat conduction equation is evaluated through the separation-of-variables method, using Bessel functions.The problem domain is defined at the finite interval bounded by the radius of thermal influence, evaluated as the heat front advances. At the borehole wall, the boundary condition is given by a constant heat transfer rate.
This solution was implemented in a computer program.The results were compared with numerical solutions. They presented a better computational performance in terms of time and model simplicity.
New Well Architecture and Structural Modeling Based on the Integration of Seismic Data, Well Logs, Core, Production and Geomechanic Data in "Carito Field", Northern Monagas Basin, Venezuela
Authors: Gomez G. , Martinez A. , Sifontes E. , Rodriguez P. , Arcia L. , Planchart C. 
Published: December 2007

Abstract
Reservoirs at the Northern Monagas Basin, EasternVenezuela, are characterized by a very complex structural modelof sand-shale sequence (highly faulted system), as well as a diverse column of fluids, such as light oil, condensated, gas and water.Depths range within 15,000 to 17,000 feet.A preliminarily model was generated from surface seismic data before drilling, and was carefully evaluated and updated based on the information obtained from drilled wells.
This paper presents an interesting case of design of new well architecture based on structural and reservoir re-interpretation of a block at Carito Field, after the integration of new 3D surface seismic data, Borehole seismic data (VSP), Crosswell seismic data and well logs (Images, Dip, Cross Dipole Acoustic logs), core and production data.
The use of novel evaluation techniques of structural geology and reservoir were complemented with the geomechanical modeling of the area. The results of this integration are used for the design of new well geometry for the optimization of the drainage of reserves associated to this reservoir.
Enhanced Oil Recovery with CO2 Sequestration: A Feasibility Study of a Brazilian Mature Oilfield
Authors: Gaspar A. T. F. S. , Suslick S. B. , Ferreira D. F. , Lima G. A. C. 
Published: December 2007

Abstract
This paper investigates the economic feasibility of extending the production life of a small mature oilfield using EOR coupled with CO2 sequestration. We describe the physical aspects of this project, as well as, present a breakdown cost methodology in order to estimate the main financial determinants of the integrated EOR with CO2 sequestration, that is, the cost of capture, compression, transportation and storage. A cash flow and risk analysis is carried out whose main result is a NPV of US$ 3.2 million. A sensitivity analysis shows that project NPV is most sensitive to oil price, oil production and CAPEX. In addition, an environmental benefit of storing 0.73 million tonnes of CO2 over 20 years is achieved.
Inorganic Scale Control Within MEG/Methanol-Treated Produced Fluids
Authors: Jordan M. M. , Feasey N. D , Johnston C. J. 
Published: December 2007

Abstract
The control of inorganic scale (carbonate/sulphate) has been a challenge to the production of hydrocarbon and associated water for over 50 years. The current trend in the industry to develop satellite fields with longer tie backs and in deeper water has resulted in new challenges to control such scale deposits during hydrocarbon production. The lower fluid temperatures that are present in these subsea developments during fluid production increases the sulphate scaling tendency and makes scale control very difficult over the long residence time now experienced due to the tie back lengths. The introduction of methanol, mono ethylene glycol (MEG) or tri ethylene glycol (TEG) to control hydrate risk presents new challenges in terms of increased scale tendency (dehydration of brine) and interactions of the hydrate control chemicals with scale inhibitor performance.
For these challenging environments a full understanding of the evolution of the brine chemistry through the field life cycle is essential (types of scale, supersaturation changes). This paper will outline the process by which this risk assessment of scale formation in the presence of hydrate control chemicals is made and how the scale control measures for effective scale management of subsea developments is carried out. Development of new and improved scale inhibitors for these types of applications within both methanol and MEG hydrate control chemicals will be outlined. Field case studies from the North Sea and Southern Africa will be used to illustrate the scale control challenges and how they have been overcome with engineering and production chemical solutions.
Detailed 3D Seismic Interpretation Using HFI Seismic Data, Fault Throw, and Stress Analysis for Fault Reactivation in the Cogollo Group, Lower Cretaceous, Urdaneta West Field, Maracaibo Basin
Authors: Galarraga M. , Hansen B. 
Published: December 2007

Abstract
As a part of the static and dynamic reservoir modeling project of the Cogollo Group in the Urdaneta West Field (SIEP & SVSA, 2003-2004), a detailed structural interpretation of 1150 km2 of HFI ("high frequency imaging") seismic volume was carried out.Five different trends of faults were interpreted, as done onthe previous PSI ("pre-stack time imaging") seismic volume two years ago (Galarraga & Engel, 2002), but substantially increasing the number of NW-SE trending normal faults interpreted. This fault trend has developed and grew parallel to the maximum horizontal stress through time. Therefore, they were used to guide the local changes in orientation of the maximum horizontal stress (sHmax) which are related to the preferential flow direction of the fluids in the reservoirs.
Fault length vs fault throw plot and fault throw analysis for the different trend of faults interpreted in the Cogollo Group suggest that most of the faults interpreted in the field are composed of more than one fault actually hard-linked in the Cogollo Group. Furthermore, comparison of the fault throw profile at the different horizon levels indicates that the throw decreases with depth in the NW-SE trending normal faults. This behavior has been observed in normal faults formed under oblique-slip faulting, according to sandbox analog experiments (Naylor, et al, 1986; Richards, 1991).
Estimation of the current stress state (Hansen and Galarraga, 2003-2004) indicated that the Urdaneta West Field is actually under strike slip tectonic (sHmax &gt; sV &gt; sHmin). Stress analysis for fault reactivation was carried out over the different trend of faults, indicating that the WSW-ENE fault trend is critical stressed (i.e. capable of slipping), and therefore permeable, allowing hydraulic communication between the Maraca and Apon reservoirs within the Cogollo Group. This is supported by dynamic reservoir modeling (Rodriguez and Morell, 2003-2004), which indicated a need for hydraulic communication between Maraca and Apon reservoirs.
Enhanced Scale Inhibitor Placement by Gravity Slumping In High-Permeability Horizontal Wells - Draugen Field, North Sea
Authors: Wahid F. , Graham G. M. , Jordan M. , Oliphant D. 
Published: December 2007

Abstract
This paper examines the impact on scale squeeze life of water/scale inhibitor re-distribution during extended shut in periods for bullhead scale treatment in a high permeability reservoir. The Eclipse 100 reservoir simulator was used to examine water re-distribution (gravity slumping) during extended shut in periods for horizontal wells in the Draugen reservoir. The work shows that in certain cases involving long horizontal wells (&gt;1000 ft) in high permeability sands (3-5D) with low vertical/horizontal permeability contrasts, extensive water re-distribution can occur during extended shut-in periods owing to density differences between the injected (aqueous) fluids and the formation fluids. Full field reservoir modelling was then carried out to identify candidate wells within the Draugen field which offered greatest potential for improved chemical placement based on these findings. Near wellbore placement modelling was then conducted to optimize squeeze return lifetimes using gravity re-distribution to improve placement deeper (lower) in the reservoir vs. convention scale squeeze design methods such as larger overflush.
The work demonstrates that for selected cases, gravity re-distribution can be used to improve placement deeper (lower) in the near wellbore area. The modeling work also identifies limitations with the simple "radial" near wellbore models for such cases and identifies those wells in the Draugen field which would benefit from such treatments. An added benefit for low water cut wells was the potential to minimise post treatment lift issues associated with the injection of high volumes of water into the near wellbore for aqueous squeeze treatments, by allowing the injected aqueous treatment to sink away from the near wellbore area. New field treatments have therefore been designed based on the work described. The economic impact of the extended shut in times vs. improved squeeze treatments and deferred oil costs for this field case are also discussed following the field applications.
A Complete Theory of Scale-Inhibitor Transport and Adsorption/Desorption in Squeeze Treatments
Authors: Sorbie K. S. , Gdanski R. D. 
Published: December 2007

Abstract
Software tools for designing downhole scale inhibitor (SI) squeeze treatments are widely available and have been successfully applied in thousands of wells worldwide. Many SPE papers have been published describing such squeeze design case studies from the conceptual modelled design, to implementation and post treatment analysis. These models are based on the fundamental transport equations for the SI in the near well formation. These equations must also include a model describing the SI/rock interaction, regardless of whether it occurs by an adsorption/desorption or by a precipitation (phase separation) mechanism. A number of papers have appeared in the literature on these fundamental equations and on the analytical and numerical models based on them.
In this paper, we present a re-evaluation of the equations that have been proposed to model SI transport and adsorption in porous media. We have analysed the various approaches in terms of two basic aspects: (a) the mathematical structure of the various equations used to describe transport; and (b) the surface chemistry assumptions and models used to describe the SI/rock retention mechanism, particularly by adsorption. We specifically focus on comparing and reconciling our own (Heriot-Watt U. and Halliburton) respective approaches, which have been developed over the last few years.
Application of Scale Dissolver and Inhibitor Squeeze Through the Gas Lift Line in a Subsea Field
Authors: Kelly M. N. , James J. S. , Frigo D. M. , Driessen D. W. , Waldie A. D. 
Published: December 2007

Abstract
The Kestrel field is an 8-km sub-sea tie-back to the Tern platform in the Northern North Sea, and consists of two gas-lifted (GL) producers supported by a single injection well. Seawater broke through at P1 in the first half of 2004, and after several months at low seawater fractions a very rapid decline observed in the downhole pressure gauge was inferred to be caused by BaSO4 scale. Although the scaling tendency was predicted to be relatively low in this Brent-type reservoir ([Ba2+] &lt; 30 mg/l in the formation water), other flow assurance causes, including sand production and liner collapse, were deemed much less likely.
The most cost-effective manner to confirm the inference of scale, as well as to recover lost productivity and prevent further deterioration in P1, was deemed to be a scale dissolver treatment deployed through the sub-sea GL line, via the crossover valve and into the well, followed by an inhibitor squeeze, similarly deployed. The rationale was that even partial recovery of productivity by the dissolver and/or arrest of further decline by the squeeze should confirm scale as the culprit. Although successful GL-line-deployed inhibitor squeeze had been reported earlier using a non-aqueous package, this was the first using conventional aqueous chemicals, as well as being the first deployed together with a scale solvent. Deployment of a solvent along the methanol line, reported elsewhere, was precluded in Kestrel by the small umbilical diameter and materials constraints. The main challenges in both Kestrel treatments included control of the fluid fronts, compatibility with the materials in the GL line, and prevention of hydrate formation, both at the start of the treatment and upon re-commencement of gas-lift injection.
We report how these challenges were met, and how GL-deployed treatments recovered productivity on P1 and demonstrated that scaling in the field could be managed in this manner in the future.
Evaluation of Inorganic Scale Deposition in an Unconsolidated Reservoir by Numerical Simulation
Authors: Daher J. S. , Gomes J. A. T. , Rosário F. F. , Bezerra M. C. , Mackay E. J. , Sorbie K. S. 
Published: December 2007

Abstract
A good understanding of in situ brine mixing is important for offshore deep water fields under water injection. Incompatibility between the injection and formation waters may result in inorganic scale precipitation in the reservoir, in the well tubing and gravel pack, in flow lines and in surface equipment. In this work, we have used reservoir simulation to model injection brine/formation brine mixing and its effect on reservoir scaling. The objective of this work is to predict in situ brine mixing and its consequences using a simulator that models the kinetics of the scaling reactions. A semi-compositional simulator was used to model the barite deposition reaction which may occur in the reservoir and in the well. In this approach, we take into account the kinetics of the reactions, rather than assuming the traditional (equilibrium) thermodynamic model. Detailed near-well modelling using local grid refinement (LGR) was carried out to forecast of the level of barite precipitation which occurred in the gravel-pack and the consequent production losses. We have also modeled scale inhibitor treatments of the scaling well and a simplified "scale removal" treatment, again including additional preventive scale inhibitor squeeze treatments.
Options and Limitations of Formation Evaluation through Casing for Casing-While-Drilling Operations in South Texas
Authors: May D. H. , Caron S. 
Published: December 2007

Abstract
The drilling of gas reservoirs like the Vicksburg and Wilcox, in southern Texas poses many technical difficulties. Among these challenges are high temperatures, over pressured zones and depleted zones.
In order to minimize the drilling risk, drill faster, and reduce the completion cost, many operators have turned to casing while drilling. While the overall risk and drilling cost may be reduced, the opportunity to adequately evaluate the various producing horizons with conventional logging tools is lost. Because of inadequate formation evaluation, zones that are water-producing, depleted, or tight may be completed, resulting in added stimulation and completion costs that can offset any cost savings achieved while drilling.
This paper will discuss various options and limitations for formation evaluation through-casing, by comparing the results of through-casing evaluation with a petrophysical analysis derived from open-hole logs.
The options will include pulsed-neutron measurements, through-casing acoustic measurements, and cased-hole resistivity.
Optimistic Approach to Control Arc Stability in Unconsolidated Sands by Downhole Emulsification
Authors: Desouky S. 
Published: December 2007

Abstract
Production of heavy oils from Egyptian unconsolidated sand reservoirs causes sand production. It was proposed to use the Downhole Emulsification technique to control arc stability in the unconsolidated sand formations. The Downhole Emulsification was proved to be a significantly effective operational technique to handle sand production. The process involves the injection of an aqueous non-ionic surfactant solution into the well-bore to convert the water/oil emulsion to oil/water emulsion retaining at the same time sand within the oil phase.
In the present work, a physical model was designed to simulate the sand production process. Then the rheological properties of oil/water and water/oil emulsions containing sand were measured at the reservoir conditions. The stability of the emulsions and sand accumulation rate were also examined under dynamic conditions. Sensitivies to water/oil ratios, surfactant concentrations, sand production rates, and different crude oils were performed in this study. Results were consequently used to optimize the composition of the aqueous surfactant solution, flow rate and settling velocity that guarantee a successful Downhole Emulsification process to keep sand in oil phase, hence control arc stability. The paper presents three case histories indicating very promising results.
The Effect of Fracture Relative Permeabilities and Capillary Pressures on the Numerical Simulation of Naturally Fractured Reservoirs
Authors: de la Porte J. J. , Kossack C. A. , Zimmerman R. W. 
Published: December 2007

Abstract
Engineers using numerical reservoir simulators to model fractured reservoirs typically have used straight-line (corner-to-corner) relative permeabilities and zero capillary pressure in the fractures, without a clear understanding of how these two parameters affect simulation accuracy and with no practical method for selecting alternate values. The present study uses the theoretical work of Rossen and Kumar (non-straight-line fracture relative permeabilities)1,2 and of Firoozabadi and Haugh (non-zero capillary pressure in rough-walled fractures)3 to quantify prediction errors and to demonstrate a method for selecting the correct set of relative-permeability and capillary curves for a particular simulation. Our results indicate that using straight-line relative permeabilities can lead to predicted oil-recovery errors as high as 70% in water-oil systems and to underestimating oil production times in some gas-oil systems by as much as a factor of three. In gas-oil systems where gas flows into the fractures, oil recovery from the matrix blocks could be underestimated by a factor of almost two when fracture capillary pressures are set at zero.
The Development and Utilization of Scattered and Remote Gas Field Resources with HSE
Authors: Yanming P. , Jian Z. , Xiaoyang L. , Jianwen Y. , Changming Z. , Xiaomu W. 
Published: December 2007

Abstract
The international community encourages fully use of natural gas, which is used to replace coal and "makes good inadequate oil with gas". It is expected that by the year of 2020, natural gas production will be increased from 25% to 40% in present energy structure in the whole world. And its rapid and stable development period could last for 40~50 years and it will be one of the most important energy sources in the preliminary period of time in the 21st century. At present, 40%~50% of natural gas resources are accumulated in scattered and remote medium and small-scale natural gas fields in the world. Since these gas fields are usually located in remote and frontier areas, transporting the natural gas, light hydrocarbons and CO2 resources of these areas by pipeline is not reasonable in regard to economy, technology and HSE.
In this paper, appropriate technical measures for separation, treatment, storage, transportion and utilization of natural gases are proposed aimed respectively at medium and small quantity of gas resources. The recovered natural gas and CO2 can be reinjected into oil wells in order to improve oil recovery efficiency. In addition, CO2 can be utilized to treat wastewater containing of CaCl2 to reduce environmental pollution. Some wastewater can be utilized to produce gas hydrate in order to store and transport gas resources.
In summary, flexible measures are needed in gas separation, treatment, storage, transportation and utilization on the basis of gas quantity, which will provide resources guarantee for fully utilizing available resources and obtaining maximum benefits.
A New Breed of Petroleum Engineering Education in the Middle East
Authors: Aggour T. 
Published: December 2007

Abstract
As the desire for nationalizing the work force in many Middle Eastern national oil companies increases, there is an increased need to provide suitable educational programs to produce highly qualified native engineers. While petroleum engineering university graduates in the Middle East will face many of the same technical issues as their counterparts around the world, the nature of their employment and their career progression can be significantly different. The unique structure of many of the national oil companies in the Middle East as well as the unique student pool allows and calls for the establishment of petroleum engineering education programs that may differ from programs in other regions of the world. This may involve modifying the structure and delivery of traditional courses of study. Universities in the region are faced with the challenge of developing programs that can more effectively address these unique needs while maintaining academic integrity and rigor, and meeting international standards for academic accreditation and excellence. This paper discusses the nature and needs of the regions employers and potential employees, and the response of regional academic institutions to cater to these needs. Examples are given demonstrating the efforts at some regional universities that are attempting to address the specific needs of the regional industry while achieving and maintaining international standards of excellence.