bluuebunny/crossref_metadata_2025_split huggingface dataset:
Productivity-Based Method for Selection of Reservoir Drilling Target and Steering Strategy
Authors: Kharghoria A. , Cakici M. , Narayanasamy R. , Kalita R. , Sinha S. , Jalali Y. 
Published: December 2007

Abstract
We present a heuristic method of delineating reservoir regions with favorable production potential for well placement. The method uses basic concepts of proxy formulation for well productivity to relate the production potential of a well placed in any region in the reservoir, to the basic properties of that region (petrophysical, dynamic, geometrical). These properties may be readily obtained from any history-matched or data-conditioned reservoir model. Therefore, a productivity potential map for the reservoir can be easily generated. Also, the relevant properties relate to parameters measurable in an LWD operation. We use this technique to simulate the impact of alternate steering strategies on well path and productivity. This requires a fine-scale model of the region designated for drilling (i.e., model prior to upscaling). The influence of additional LWD measurements on reservoir trajectory and expected well performance can therefore be assessed with this technique (e.g., impact of NMR-derived permeability). We also examine how this method may be applied when multiple geological scenarios are conceivable for the area targeted for drilling. We apply a simple technique for model aggregation that proves effective in identifying drainage areas that are optimum or near-optimum in an overall sense. Therefore, a well placed in the region identified by the aggregate model shows a performance with respect to the underlying geological models that is best or not far from it.
Simulation of Time-Dependent Wellbore Stability in Shales Using a Coupled Mechanical-Thermal-Physico-Chemical Model
Authors: Freij-Ayoub R. , Tan C. P. , Choi S. K. 
Published: December 2007

Abstract
The interaction of the drilling fluid with the formation rock is a key factor that determines the time-dependent stability of wellbores in shale formations. The analysis of wellbore stability in shales requires modelling of various coupled processes that are dependent on the relative properties of the drilling fluid and formation pore fluid. These processes include mud pressure penetration, thermal diffusion, chemical potential mechanism and poroelasticity. These processes affect the formation pore pressure, stresses and deformation. The critical drilling fluid properties include mud type, weight, temperature, and type and concentration of free ions.
Numerical simulations are conducted to model the effect of coupling the various processes on wellbore stability in shales. The simulations used a finite element code SHALESTAB that solves the specific coupled differential equations which describe these processes. It is found that the use of a cooler drilling fluid with a higher salt concentration and the appropriate mud density, viscosity and surface tension reduces the formation pore pressure and helps to enhance the stability while the use of a hotter drilling fluid with a lower salt concentration and less favourable mud physical characteristics has the reverse effect. The coupled simulations show that incorporating the chemical potential and mud pressure penetration mechanisms, depending on the mud properties, can reduce the formation pore pressure. For an effective assessment of wellbore stability in shales, the analyses need to take into account these complex coupled time-dependent processes.
Applying Electrophoresis Technique to Study Adsorption of Surface Active Agents on Reservoir Rocks
Authors: Elmofty S. E. , Shokir E.M. El-M. 
Published: December 2007

Abstract
Interfacial behavior of fluids in contact with sandstone is governed to a large extent by their surface electrochemical characteristics, pH of the surroundings, concentration of the dissolved ionic species and the existence of any surfactant control surface properties. In this study electrokinetic properties of sandstone are reported as a function of the pH and in the presence of different concentrations of sodium chloride, modified natural polymers and anionic and nonionic surfactants. Mechanisms of adsorption of the previous mentioned surfactants on sandstone are discussed. Measurements of wettability and a correlation between the electrokinetic results are investigated. The surface electrochemical characteristics of the sand was found to play a governing role in determining the mechanisms of adsorption of the studied surfactants.
Empirical Equations for Water/Oil Relative Permeability in Saudi Sandstone Reservoirs
Authors: Al-Fattah Saud M. 
Published: December 2007

Abstract
Relative permeability data are essential for almost all calculations of fluid flow in petroleum engineering. Water/oil relative permeability curves play important roles in characterizing the simultaneous two-phase flow in porous rocks and predicting the performance of immiscible displacement processes in oil reservoirs. This paper presents new empirical equations for calculating water/oil imbibition relative permeability curves. The models of relative permeability were developed using experimental data from 46 displacement core tests from sandstone reservoirs of Saudi fields. Three empirical equations are presented to calculate oil relative permeability, water relative permeability, and the endpoint of the water relative permeability curve. The relative permeability models were derived as a function of rock and fluid properties using stepwise linear and nonlinear regression analyses. The new empirical equations were both evaluated using the data utilized in the development and validated using published data, which were not used in the development stage, against previously published equations. Statistical results show that the new empirical equations developed in this study are in better agreement with experimental data than previous empirical equations, for both the data used in the development and validation stages. The new empirical equations can be used to determine water/oil relative permeability curves for other fields provided the reservoir data fall within the range of this study.
Pressure and Compositional Gradients in Reservoirs
Authors: Montel F. , Bickert J. , Hy-Billiot J. , Royer M. 
Published: December 2007

Abstract
The search for the optimal development of a field involves proper knowledge of the composition of the fluids that impregnated the reservoirs. The development scheme could be strongly affected by the connectivity between the different reservoir units. After their migration into the trap, the fluids are shaped by various forces, among them, gravity has the most striking effect and was widely studied. In many cases there is evidence for the contribution of other forces like thermal gradients. Taking into account all the phenomena, to establish a consistent picture of fluids distribution in the field is an important challenge for the petroleum industry. Reciprocally the actual fluid distribution can be used to assess the connectivity of the different panels and layers. In that case, all the possible compositional redistribution mechanisms have to be taken into account.
In some circumstances, particularly in recent mature and permeable petroleum systems, hydrocarbon accumulations are subjected to gas fluxes, which lead to non-conventional fluid distribution. There are already a number of tools available for calculating the compositional gradient within a reservoir, including the contribution of gravity and thermal gradient. In many field cases, however, the calculated profile differs from actual. The discrepancies are imput to another external force: the mass flux of light component at the reservoir boundaries.
In this paper, the authors present the modeling of diffusion fluxes across the reservoir and point out how the diffusion fluxes can reveal the permeability barriers through the pressure and the compositional profiles.
Drawing on a field example, this paper provides a methodology for dealing with dynamic reservoir fluid systems. The model matches the observed compositional gradient and corresponding PVT properties. It allows reliable connectivity assessment in cases where gravitational modeling fails.
Improved Reservoir Description using Surface Oil Viscosity Data
Authors: Umeh N. , Isehunwa S. , Okorafo C. , Owolabi S. , Agu I. , Olare J. , Biambo T. 
Published: December 2007

Abstract
Subsurface oil viscosity data are usually not readily available for most reservoirs, as they are expensive to acquire. On the other hand, surface oil viscosity is routinely measured and therefore readily available for all producing wells. A method has been developed for converting the surface viscosity to reservoir viscosity data, using SPDC’S "Field A" as a case study.
Surface oil viscosity data from all producing wells in "Field A" where collected from SPDC-West Production Chemistry laboratory and converted to reservoir viscosity using a simple method that utilises relevant PVT data. The method allows a better and more detailed subsurface description of reservoir viscosity in line with facies variations. The study also shows that reservoir oil viscosity could be lower in some sands than previously estimated. This gave a significant impact on reserves in one of the reservoirs where scope to increase the booked reserves by about 60 MMstb was observed. Opportunity to also increase the constrained offtake of 2300 b/d to 3000 b/d in some planned new wells was also observed.
A New Scaling Equation for Modeling of Asphaltene Precipitation
Authors: Jamialahmadi M. , Ahmadi K. 
Published: December 2007

Abstract
The amount of asphaltene precipitated is a crucial factor in determining the degree of permeability impairment of the reservoir rocks. It is useful to know how much asphaltene precipitates as a function of temperature, pressure and liquid phase composition. The objective of this work is to present a simple and accurate mathematical model, capable of predicting the amount of asphaltene precipitated at a given operating condition.
Extensive new experimental data for the amount of asphaltene precipitated in an Iranian crude oil has been determined with various solvents and at different temperatures and dilution ratios. All experiments were carried out at atmospheric pressure. The experimental data obtained in this study were used to examine the scaling equations proposed by Rassamdana et al. [1,2]. We introduced a modified version of their proposed scaling equation.
Our observation showed that the results obtained from the present scaling equation are in good agreement with experimental data at low value of dilution ratios. The properties of complex asphaltenes are not considered in this simple model. We strongly recommend this model for laboratory experiments and core flood tests which are often performed at atmospheric pressure and practically at low value of dilution ratios.

Introduction
Asphaltene precipitation is one of the most common problems in both oil recovery and refinery processes. In oil recovery, especially in gas injection, formation of asphaltene aggregation, following their deposition causes blocking in the reservoir. This makes the remedial process costly and sometimes uneconomical. Unfortunately, there is no predictive model for asphaltene problem treatment. Hence it is necessary to predict the onset of asphaltene precipitation, as a pre-emptive measure. The major questions in facing such problems are " When" and " How much" heavy organic compounds will precipitate in operational condition. Over the years, many researchers have tried to find the answer. They introduced experimental procedures or even analytical models, but a fully satisfactory interpretation is still lacking. The problem is very difficult mainly because of the fuzzy nature of asphaltene and the large number of parameters affecting precipitation.
Low-Resistivity Pay (LRP): Ideas for Solution
Authors: Souvick Saha 
Published: December 2007

Abstract
Low-resistivity pay (LRP) has been a long-standing problem in formation evaluation. Though LRP occurs both in carbonates and sandstones, it is more common in sandstone reservoirs. Because of LRP, one may overlook the zone or compute high water saturation (Sw) leading to "condemning" the zone or underestimating the reserve.
Because of the complexities that contribute to LRP, the cause must be determined before an appropriate solution can be applied. LRP can occur because of several reasons, such as, deep invasion by conductive borehole muds, "classic" clay problem (i.e. cffect of cation exchange capacity, CEC), presence of capillary bound water, conductive minerals (such as pyrite), fractures, micro-porosity, laminated formations and high angle wells (anisotropy effect). When more than one of these effects is present in the formation, the solution is even more difficult. Nevertheless, once the reason of LRP is understood, several logging tools and/or interpretation techniques can be applied to compute accurate Sw. In Nigeria where reservoirs are mainly sandstones, the predominant effect of LRP is due to clay, capillary bound water, laminated
formations and high angle wells. New logging technologies including new modern resistivity (both wireline and LWD), magnetic resonance, elemental spectroscopy and high-resolution borehole images contribute significantly to solving for LRP problems.
Finally, after correcting for Sw in LRP, the new Sw needs to be validated. The validation can be done with core data; there are two common methods, direct Sw measurements from oil-based mud cores 1 and computing from capillary pressure data. Direct Sw measurement is rather expensive procedure, whereas Sw from capillary pressure data can be computed easily with knowledge of the height above free water level and core plug permeability. Thus, finding the cause, applying the right technique to compute accurate Sw and validating the result by core integration can solve LRP problem. This will lead to improved decision in well completion, reserve estimation and reservoir simulation for accurate production forecasting.
Intelligent Well Completion: Status and Opportunities for Developing Marginal Reserves
Authors: Konopczynski Michael , Ajayi Arashi , Russell Leigh-Ann 
Published: December 2007

Abstract
Marginal reserves are hydrocarbon accumulations too small or too difficult to recover economically by themselves under prevailing fiscal terms. Stacked reservoirs containing marginal reserves are often passed over in favour of more prolific zones containing economic volumes. The opportunity to develop the marginal reserves in conjunction with other marginal reserves, or with larger reserves by commingling (and by doing so make them economic) is sometimes overlooked by operators due to government regulations prohibiting commingling.
This paper explores the concept of developing marginal and/or other reserves by commingling using intelligent well technology. It reviews the current status of intelligent well technology and government regulations on commingling in a number of regions. The potential for exploiting marginal reserves in the North Sea, Nigeria and the Gulf of Mexico is also considered.
Simulation of Intelligent Well Completion Predicts Oil Recovery Increase in a Commingled Production Scenario: A Case Study
Authors: Ajayi Arashi , Konopczynski Mike 
Published: December 2007

Abstract
Water coning has been observed to have a negative impact on the productivity of producing wells. This situation often results in reduction of recoverable oil reserves. The application of Intelligent Well Technology (IWT) offers an operator the opportunity to manage this adverse effect and improve productivity of such wells. IWT provides an operator the capability to remotely control, monitor and manage multiple horizons in a given well. Application of the technology has provided significant value, through the ability to control multiple zones independently, reduce total number of wells, reduce future costly well intervention, and accelerate production of zones to maintain a plateau for extended period of time.
This paper presents the results of a simulation case study carried out in a Gulf of Mexico field. The study objective was to assess the capability of an IWT completion to control excessive downhole water production and maximise total oil volume in a three layer reservoir system. A dynamic optimisation technique was used in the reservoir simulator to independently control the Interval Control Valves (ICVs) in each zone to achieve the desired production objective. The ICVs are modelled as downhole chokes that are connected to a standard well model. The optimisation procedure monitors these chokes while the simulation is running and controls them as required.
The results show that the IWT system was able to minimise the volume of water produced by the well in the studied coning condition when compared to conventional system. This is mainly due to the choking capability of the ICVs. We also estimated an oil recovery increase of about 63% when compared to a conventional system. Potential applications of the technology should be assessed with regard to well/reservoir objectives.
A Comprehensive Numerical Simulation Model for Non-Darcy Flow including Viscous, Inertial and Convective Contributions
Authors: Belhaj H. A. , Agha K. R. , Butt S. D. , Islam M. R. 
Published: December 2007

Abstract
In this paper, a comprehensive numerical simulation model is introduced to resolve the problem of non-Darcy flow in porous media. As represented by this model, both pressure gradient and velocity profile predicted are based on the two viscous terms of Darcy and Brinkman, Forchheimer’s inertial term and Navier-Stokes’ convective term. At the point of departure from the Darcian domain to the non-Darcian domain it has been found that this model predicted the dimensionless term "Be" to be zero which agrees with Forchheimers model prediction. At 5% deviation from the Darcian flow the proposed model predicts "Be" to be 0.0756 as compared to 0.0526 predicted by Forchheimers model. The difference is due to higher flow velocity prediction by the proposed comprehensive model.
The proposed model is expected to have wide applications in the field of reservoir simulation and fluid flow in porous media in both gas and oil reservoirs. Replacing the traditional model used to predict pressure gradient at any point of space and time by the proposed model would resolve the problem of inaccurate predictions associated with non-Darcy flow. This model predicts the correct pressure gradient and flow velocity regardless of the source of deviation. The model is continuous in Darcian regime as well as non-Darcian regime.
Development Evaluations of Lenticular Shallow Gas Reservoirs with Bottom Water in Shengli Oilfields
Authors: Sheng Ruyan , Cui Chuanzhi , Ding Liangcheng 
Published: December 2007

Abstract
Shallow gas reservoirs are widely distributed in China and mostly occur at depths shallower than 1500 metres (4921.50 ft). These occur as lenticular and marginal reservoirs, with small and scattered reserves, with quite complex gas-water relationship and edge/bottom water in the majority of sand-bodies. Each sand-body forms an unattached and closed gas-water system, but there is limited elastic energy in the aquifer. The production performance of one of such reservoirs is as follws: –Per-well initial gas rate is rather low with fast decline.–The reservoir has a gas drive to weak elastic water-drive.–Water incursion has obvious influences on production results.–Wellhead pressurse could be used to represent the changes of formation energy, for it is impacted little by wellbore accumulated liquid.–Finally, formation damage resulting from drilling, perforating etc. has noticble influences on the gas wells’ performance.
Thus the main factors that could decide reasonable well rates should be the following factors: Efficient utilization of formation energy, reservoir structure should not be destroyed, accumulated liquids in the wellbore should be continuously removed. In addition better development results can be achieved through initial sand control and edge/bottom water fingering/coning should be minimised.
The purpose of this paper is to have a review of the parameters and the performance of the Shengli oil reservoirs. It could be used for reference for similar type of reservoirs.
Improved Safety of Rig Automation with Remote Monitoring and Diagnostics
Authors: Levett Bryce 
Published: December 2007

Abstract
Rig automation has focused on improving safety with equipment designed to reduce manpower/human interaction and assume repetitive tasks and operations. As more parts of a drilling rig become automated, there has been a change in how rig personnel interact with equipment. A system of remote monitoring, diagnostics and technical support has been developed to make this interaction more seamless and expand the focus of rig automation. Case studies are presented in this paper of actual field conditions where the remote monitoring system eliminated hazardous operations, discovered operational "bad habits", and identified areas requiring additional training. Use of the remote diagnostic system prevented the need for physical contact between human and machine in order to solve problems. Documented field incidents have shown benefits of increased safety in many areas when using remote monitoring and management compared to operations without.
Standardised Procedures for Work Permits and Safe Job Analysis on the Norwegian Continental Shelf
Authors: Botnevik R. , Berge O. , Sklet S. 
Published: December 2007

Abstract
Promoting safety in an offshore environment where more than 2/3 of the workforce travel between different operating companies and installations represents a continuous challenge since the procedures and requirements are different from installation to installation. The Work Permit (WP) system and the use of Safe Job Analysis (SJA) represent essential operational safety barriers required in the daily management of work and safety on oil and gas installations.
Through a process of dialogue and participation, involving the offshore community a standardised procedure for WP and SJA has been developed and approved for implementation on all production installations on the Norwegian Continental Shelf (NCS). The objective of this industry wide change is to improve safety and working conditions offshore through the use of standardised procedures and practices.