bluuebunny/crossref_metadata_2025_split huggingface dataset:
Case Studies Illustrating the Use of Reservoir Simulation Results in the Reserves Estimation Process
Authors: Rietz Dean , Usmani Adnan 
Published: December 2007

Abstract
Continuous improvements in reservoir simulation software and the availability of high performance computing equipment are making the use of simulation models commonplace for field development and planning purposes. Naturally, this trend has also increased interest in the use of reservoir simulation model results in the oil and gas reserves estimation process.
As simulation specialists who work in a primarily reserves-evaluation company, the authors are routinely asked to evaluate, and in many cases incorporate, simulation results in the reserves estimation process. In addition, the authors are required to opine on the approach and tactics used by clients while they incorporate numerical models in their reserves bookings. Since there exists limited published discussion on this topic, the purpose of this paper is to provide some examples of the approach used by the authors. We believe this approach to be appropriate and within the spirit of reserves interpretation as used by typical reserves regulatory bodies such as the U.S. Securities and Exchange Commission (SEC).
Papers previously published have discussed the use of models in the reserves process, including the evaluation of the models' themselves1,2. In contrast, this paper provides three case studies that illustrate how results from various models have been used to assist in quantifying reserves. Two of the examples are based on history matched models while the third focuses on a pre-production reservoir where no adequate history is available and probabilistic methods were incorporated to help understand the uncertainty in the forecasts.
While there is no "cookbook" or step-by-step procedure for using simulation results to estimate reserves, the case studies presented in this paper are intended to both show some examples and also spark some debate and discussion. Undoubtedly there will be some disagreement with our techniques, but an open discussion should prove to be beneficial for both reserves evaluators and simulation specialists.
Advances in Drillpipe Fatigue Management
Authors: Gokhale Samit R. , Zoanni Richard , Zheng Nanjiu , Everage DeWayne 
Published: December 2007

Abstract
Recent improvements in manufacturing quality control have dramatically reduced drillpipe failures caused by insufficient material properties. However, preventable fatigue-induced failures continue to occur at a high frequency. Increased drilling activity, rising rig spread rates and the technically challenging nature of today's ultra deep and extended reach wells dictate the need for an effective drill pipe fatigue management system. This paper discusses the cumulative fatigue damage approach as applied to drill pipe and presents a field-implemented fatigue management strategy that can significantly improve the overall fatigue performance of the drill string.
Drill pipe fatigue analysis has been approached through both total fatigue life and fracture mechanics models. The fracture mechanics model was used to develop the concept of comparative fatigue design introduced in a previous paper (IADC/SPE 87188). Comparative fatigue design allows for a quantitative comparison of drill string design and well bore geometry alternatives based on normalized fatigue crack propagation and various known well bore parameters like dogleg severity, hanging tension, drill pipe size, hole size, etc. However, this "snapshot" technique only provides an insight into the fatigue performance of the drill pipe under one set of operating conditions. A joint of drill pipe experiences substantial variations in loading conditions at different depths along the well bore trajectory. Hence the comparative fatigue design technique was further refined to consider all significant operating conditions and allow quantitative comparison of cumulative drill pipe fatigue damage.
The cumulative fatigue damage technique has been successfully applied as a design tool to compare different drill string configurations, well bore trajectories and drilling operations. This technique can also be applied in calculating relative fatigue damage within different well bore sections and the entire well bore, thus identifying sections of the drill string that will accumulate maximum fatigue damage after a series of operations. Sections of drill pipe may then be repositioned within the string or pulled and reinspected to minimize the risk of fatigue-induced failures.
Simulation of Compositional Gravity Drainage Processes
Authors: DiCarlo D. A. , Jessen K. 
Published: December 2007

Abstract
The amount of wetting phase that is recovered by gravity drainage when the displacing fluid is not in chemical equilibrium with the initial fluid involves a complex interplay of gravitational, diffusive, and capillary forces. Recently, in Part 1 in a series of papers, we proposed analytic solutions for capillary/gravity equilibrium (CGE) in compositional gravity drainage, and estimated the total recovery of wetting phase. In Part 2 we presented the results of experiments in an analog brine/isopropanol/iso-octane system (with non-parallel tie lines) in which the vertical profile of the components was measured destructively after 3 weeks of drainage. The condensing drainages compared favorably to the CGE solution and the vaporizing drainages to analytical solutions for advection dominated transport. Here we present numerical simulations of compositional gravity drainage. We find that the CGE solutions are approached asymptotically as the simulation grid is refined for a simplified phase diagram. For vaporizing drainages, a bank of wetting fluid is found to be created from early times in the drainage through wetting fluid imbibing back into swept regions. We show that including hysteresis in the capillary pressure curve limits the creation of the wetting fluid bank. We compare the numerical simulations to the experimental observations, and find the simulations match well for condensing drainages, but not for vaporizing drainages, similar to that seen for the CGE solutions.
The Use of Capacitance-Resistive Models for Rapid Estimation of Waterflood Performance and Optimization
Authors: Sayarpour M. , Zuluaga E. , Kabir C. S. , Lake Larry W. 
Published: December 2007

AbstractThe capacitance-resistive model (CRM) offers the promise of rapid evaluation of waterflood performance. This semianalytical modeling approach is a generalized nonlinear multivariate regression technique that is rooted in signal processing. Put simply, a rate variation at an injector introduces a signal, with the corresponding response felt at one or more producers. CRM uses production and injection rate data and bottomhole pressure, if available, to calibrate the model against a specific reservoir. Thereafter, the model is used for predictions.We focused on three different control volumes for CRMs: the volume of the entire field, the drainage volume of each producer, and a drainage volume between each injector/producer pair. Unlike the numerical simulation approach, the CRMs use only production/injection data to predict performance, which provides simplicity and speed of calculation.Once the CRM is calibrated with historical production/injection data, we use an optimization technique to maximize the amount of oil produced by reallocating water injection rates. To verify CRM predictions, the models were tested against numerical flow-simulation results. Two case studies showed that the CRMs are able to successfully history match, and maximize the amount of oil produced by just reallocating water injection.This study introduces analytical solutions to the fundamental differential equations of the capacitance model based on superposition in time. In so doing, this approach adds flexibility, simplicity, and computational speed to the work presented previously.
Current State of the Premium Screen Industry: Buyer Beware—Methodical Testing and Qualification Shows You Don't Always Get What You Paid For
Authors: Adams Peter R. , Davis Eric R. , Hodge Richard M. , Burton Robert C. , Ledlow Lewis , Procyk Alex D. , Crissman Seth C. 
Published: December 2007

Abstract
Within the sand control technology sector today, there are many sand exclusion screen options available for use in completion design. Sand control screens have steadily improved with the introduction and enhancement of metal sand retention media based sand exclusion products in the early 1990's. However, recent catastrophic sand exclusion failures have led some operators and independent laboratories to perform additional testing and quality control checks on sand exclusion products to ensure full life cycle field value.
This paper describes a process to select sand exclusion products by uniquely qualifying an individual product design which includes retention media, metallurgy, subcomponents, manufacturing process, and the final assembled product. The technical evaluation is based on a 2-tier qualification process that "uniquely qualifies" products for purchase consideration. Step 1 of the process tests the sand retention media for plugging potential and solids retention. Step 2 then tests full-joint screens manufactured using media qualified during Step 1 for burst and collapse to ensure the product meets downhole performance specifications.
Recent testing has illustrated a range of significant conclusions that the industry should be aware of:
Published screen burst and collapse ratings are not always equivalent to actual screen performance. Burst and Collapse pressures are not equivalent to basepipe rating. Welds can vary by plant; therefore screens may vary by manufacturing location. Excessive drainage layer gap leads to premature burst or collapse failure. Not adjusting screen design for changes in metallurgy may lead to premature failure Delamination has been observed in some sintered retention media. Scaling a product design up or down without conducting a detailed engineering analysis may lead to premature failures.
Resurrecting a Low-Pressure Gas Well Offshore: Through-Tubing Foamer Injection via a Capillary Tubing System and a Specialized WRSCSSV
Authors: Bolding Jeff L. , Hartman Larry E. , Szymczak Steve J. 
Published: December 2007

AbstractLiquid loading can have a detrimental impact to the production rate in gas wells causing many wells to be shut-in prematurely. Many artificial lift methods have successfully alleviated liquid loading and allowed the operator to reach the abandonment pressure more quickly, reducing expense. However, most artificial lift methods are not applicable to offshore production due to the regulatory requirements of certain safety systems, in particular an SCSSV (Surface Controlled Sub-Surface Safety Valve) and SSV (Surface Safety Valve), which would be impeded if traditional artificial lift methods were used.A fail-safe, through-tubing capillary injection system has now been applied to an offshore well having an SCSSV and SSV. The offshore well maintained full compliance and functionality of the SCSSV by utilizing a specialized WRSCSSV (Wireline-Retrievable Surface Controlled Sub- Surface Safety Valve). The SSV was addressed through the application of a unique wellhead adaptation called a Y-body. These two systems were combined with a capillary foamer injection string that allowed the well to flow at a lower bottomhole pressure. This lower flowing pressure enabled additional reserves to be produced and has improved the ultimate recovery from the reservoir.
Mercury Removal Project: Issues and Challenges in Managing and Executing a Technology Project
Authors: Sainal Muhamad Rashid , Mat T. Mohd Uzaini T. , Shafawi Azman , Mohamed Abdul Jabar 
Published: December 2007

Abstract
This paper will share the experience of PETRONAS in managing and executing its Mercury Removal Project, one of the world's first mercury removal projects for raw and untreated condensate. It focuses on the selection of the appropriate technology for the project, the additional steps taken in mitigating the project risks, and the issues and challenges encountered during project execution. The paper will also share the challenges faced during commissioning and initial operation of the plant, and ways taken to mitigate the problems. This includes addressing issues of impurities, particulates, water, and in monitoring the performance of handling high pressure samples for mercury content determination, as well as fluctuation of mercury concentration in the hydrocarbon stream.
A project to remove mercury from hydrocarbon was initiated by PETRONAS on a fast track basis. The intent of the project is to remove mercury from the hydrocarbon prior delivering it to the downstream customer. Since the technology in removal of mercury from raw condensate had not been commercially proven before, a thorough selection process was undertaken in selecting the appropriate technology. Adsorbent technology was selected against other technologies evaluated.
The project managed to be completed ahead of time, with the first unit installed in March, 2006 some 13 months from project initiation. The results during the monitoring period proved that the unit managed to remove mercury successfully exceeding the project requirement. The data obtained from the performance monitoring of the unit was required to improve the removal efficiency and to sustain the units' long term effectiveness. It was observed that a different project management approach was needed in executing a technology project. A proper selection of technology was also vital in ensuring the success of the project.
Mercury is highly toxic, particularly when present in the form of organo-mercury species. Mercury not only is hazardous to human health and the environment but could also attack equipment components that have mercury reactive material, leading to potential catastrophic failure to the plant. With the ability to remove mercury from the hydrocarbon stream effectively, danger to human and the environment can be minimised and catastrophic failure to the plants prevented.
Making Mature Shale Gas Plays Commercial: Process vs. Natural Parameters
Authors: Walser D. W. , Pursell D. A. 
Published: December 2007

Abstract
Fort Worth Basin Barnett Shale fiscal success and completion methodology have matured to the point that analog plays all over the North American continent are being actively sought and tested. It is probable that additional potential plays outside the current active areas exist, and that sufficient infrastructure may be present (or could be present) to develop them.
Low permeability shale gas extraction has only become generally commercial over the last five to six years. Finding and developing this type of reservoir involves matching a number of naturally occurring parameters with an extraction process that is both detailed and capital intensive.
This paper will address the natural parameters that must be present for a commercial play to be viable. It will cover the latest process and engineering improvements (stimulation and other completion issues) that have shown to improve the overall net present value of the various properties. Wildcatting strategies will be addressed, including minimizing "science" costs and reducing the time required to advance up a given learning curve.
Ensuring the Return on Investment for Training Programs
Authors: Aggour Tamir 
Published: December 2007

Abstract
In recent years there has been a large focus on implementing structured competency assurance programs within large oil companies. The goal of these programs is to ensure that a company's workforce is competent to carry out the required job functions in an efficient and safe manner that will maximize the financial success of the company. Most programs involve a description of the various job functions and their required competencies, with a progression from basic knowledge to skill and mastery. By tracking employees training against competency maps, gaps in knowledge and skills are identified, and the required supplementary training is implemented to close the gaps. This training can range from classroom instruction to field assignments.
In theory, once an engineer has completed the prescribed training, they will have achieved a specific competency level. However, in many cases there is no formal assessment after completing training courses to confirm that the engineer has indeed increased their competency. It is often assumed that, by virtue of completing a course or program, the engineer will then have achieved the specific skill or competency intended. This paper demonstrates the need for a more formalized assessment process to be associated with competency assurance programs to ensure that the large financial investments involved are worthwhile. Examples of existing programs are given along with suggestions on how to effectively integrate effective assessment programs. The difficulties in implementation and the resistance from engineers and managers associated with different forms of assessment are discussed, along with recommendations on how to address these concerns and maximize the return on training investments. General recommendations on how to ensure and improve the effectiveness and quality of short courses are also presented.
A Consistent and Accurate Dead-Oil-Viscosity Method
Authors: Bergman David F. , Sutton Robert P. 
Published: December 2007

Abstract
The calculation of pressure drop resulting from the flow of oil through porous media or pipes requires the evaluation of viscosity. This is the single most important transport property necessary to accurately calculate pressure drop. The basis for oil viscosity calculations using a traditional black oil approach is the determination of dead or gas free oil viscosity.
A total of 23 dead oil viscosity calculation methods have been identified from the literature and evaluated in this paper. A large database consisting of data from conventional PVT reports, crude oil assays and the literature was compiled from over 3000 samples from around the world. The number of actual viscosity measurements exceeded 9800. An evaluation of the correlations yielded unacceptable results largely due to the failure of the methods to properly account for the physics of the problem. In general this results from the methods’ failure to properly account for the change in viscosity with temperature and to address the chemical nature of the oil. A significant improvement in results can be realized through the use of the Watson characterization factor in addition to oil API gravity and temperature in the correlation of viscosity. This work has identified the character of the crude to have a significant effect on oil viscosity especially for oils with gravities less than 25 API.
Methods have been proposed in the literature that utilize the Watson characterization factor; however, these have been largely ignored in the upstream oil industry. Therefore, a new method has been developed which shows significant improvement over existing methods. At reservoir conditions, a 2-13 fold reduction in average absolute error was noted when compared with the error observed from traditional methods. At surface process conditions, this improvement ranged 3-60 fold. In addition, an updated correlation for Watson characterization has been developed. The ASTM density correction for changing temperature has been examined. Revised coefficients were developed which enhance the method's accuracy for both oils and pure components and provide a suitable means to convert kinematic viscosity to absolute viscosity.
A Method for Computation of Volumetric Sweeps for Individual Wells in a Waterflood
Authors: Huh Dae Gee , Ershaghi Iraj 
Published: December 2007

Abstract
In this study, we have developed a procedure for estimation of volumetric floodable oil for producing wells in confined watrerfloods from their performance data. For a given pattern, from the composite performance of all producers, we derive a set of field based relative permeability ratio vs. saturation using the procedure published by Ershaghi and Omoregie1 (JPT Feb 1978). This requires a prior estimation of volumetric floodable oil in place for the entire block. Extending the same process to individual wells can generate a set of relative permeability ratios vs. the cumulative oil production. The conversion of cumulative production to saturation requires an estimation of volumetric floodable oil in place in the drainage areas of individual wells. An iterative procedure is used to estimate the floodable oil in place per individual producers when the reconstructed relative permeability set for a given well matches that derived for the entire flood pattern. Comparison of estimated oil within the drainage area, to that assigned from pattern geometries, generates drainage area invasion efficiency for each producer that is indicative of effective volumetric sweeps.
Flow Instability Associated With Wettability Alteration
Authors: Tripathi I. , Mohanty K. K. 
Published: December 2007

Abstract
Wettability of a reservoir rock can be altered by changing brine composition, e.g., lowering salinity, adding surfactants. Wettability alteration can mobilize stranded oil and enhance oil recovery. Analytical solution for 1D tertiary low salinity flood shows two saturation shocks one of which is associated with an adverse mobility ratio. The adverse mobility ratio across this shock is not very large, about 1.5 to 3.75 in the cases considered. As the viscosity ratio increases, the width of the oil bank decreases and one of the shocks disappears at high viscosity ratio (&gt;10). The remaining shock at high viscosity ratio is stable. A viscous fingering model is applied to describe the flow instability in relatively homogeneous multi-dimensional porous media. It shows that the viscous fingering is mild and the breakthrough of low salinity injectant is only 11-31% faster than in the 1D flow. If only salts are used for wettability alteration, the capillary pressure is significant and becomes more positive (more water-wet) at low salinity. Positive capillary pressure can provide stability to the flood fronts, unlike surfactant floods where low interfacial tension removes the stabilizing capillary pressure. Low salinity floods are expected to be mildly unstable due to low mobility ratio at adverse saturation shocks and presence of capillary pressure.
Temperature Effects on Surfactant-Aided Imbibition Into Fractured Carbonates
Authors: Gupta R. , Mohanty K. K. 
Published: December 2007

Abstract
Little oil is recovered from fractured oil-wet carbonate rocks by waterflooding. Surfactant treatments are being developed to enhance oil recovery from such formations. This work investigates the effect of temperature on such surfactant treatments. Anionic and nonionic surfactants have been identified for oil recovery from fractured low permeability carbonate rocks at high temperatures. For most of the surfactants studied, optimal salinity decreases slightly or remains unchanged with an increase in temperature. Contact angles on initially oil-wet calcite plates decrease on addition of most of the surfactants; the final contact angle decreases with the increase in temperature for all the surfactants in the current study. Oil recovery rate due to surfactant solution imbibition increases with temperature for all surfactants. At 90°C, high recovery (~60% OOIP in 30 days) was obtained for many surfactants at very low surfactant concentrations (&lt;0.1 wt%) in tight (~15 md) carbonate cores. Surfactant brine imbibition was found to be a gravity driven process. Increase in temperature leads to reductions in viscosity and contact angle (which in turn increases oil relative permeability) which enhances the oil recovery rate.