bluuebunny/crossref_metadata_2025 huggingface dataset:
Real-Time Fiber-Optic Casing Imager
Authors: Appel M. , Dria D. , Freeman J. , Rambow F. , Shuck M. , Childers B. , Poland S. , Dominique T.
Published: December 2007

During the last years, significant progress has been made in the use of fiber-optic technology for well and reservoir surveillance purposes. While most effort in this field appears to be concentrated on the development of fiber-optic based temperature-, pressure- and flow meters, comparably few publications have been made to-date about the use of fiberoptic technology for monitoring deformations of well tubulars and casings.

In this article we report on recent advances in our development of a real-time fiber-optic based casing imager. This device is designed for continuous, high-resolution monitoring of the shape of casings or well tubulars and, therefore, enables the determination of strain imposed on the well. Small-scale and full-casing-size laboratory tests have demonstrated that the latest generation of this system is sufficiently sensitive to detect casing deformations of less than 10 degrees per hundred feet and covers compressive and tensile axial strain ranges from less than 0.1% to 10%. We will discuss the background technology, the measurement sensitivity and strain-response characterization, as well as the scale-up work that has been performed to-date. Our article also includes an overview of field test results and illustrates how real-time deformation monitoring could form a significant component of reservoir surveillance strategies.
Effect of Internal Baffles on Volumetric Utilization of an FWKO—A CFD Evaluation
Authors: Lu Yaojun , Lee Joseph M. , Phelps Daniel , Chase Ryan
Published: December 2007

This paper presents the results of a CFD evaluation on the effectiveness of perforated plate baffles for improving flow and separation performance in a FWKO separator. Using the multiphase model coupled with turbulent interaction, a full scale 3D simulation on two FWKO configurations indicated that with installation of the perforated plate baffles, the short circuiting and recirculation flow in the vessel was reduced. As a result, the mean residence time increased from 630 seconds to 980 seconds for the water phase, and from 520 seconds to 745 seconds for the bitumen phase. Accordingly, the volumetric utilization for the bitumen phase was increased from 46% without the baffles to 66% with the baffles, which corresponds to a 43% improvement. Water phase volumetric utilization was increased from 57% without the baffles to 89% with the baffles, which was increased by 55%. Therefore, an overall 50% improvement on the liquid phase was achieved due to the introduction of the specially engineered perforated plate baffles.
Fluid Density and Viscosity Effects on Borehole Resistivity Measurements Acquired in the Presence of Oil-Based Mud and Emulsified Surfactants
Authors: Salazar Jesus M. , Malik Mayank , Torres-Verdín Carlos , Wang Gong Li , Duan Hongyan
Published: December 2007

We quantify the influence of oil-base mud-filtrate invasion and formation fluid properties on the spatial distribution of fluid saturation and electrical resistivity in the near-wellbore region. The objective is to appraise the sensitivity of borehole resistivity measurements to the spatial distribution of fluid saturation resulting from the compositional mixing of oil-base mud (OBM) and in-situ hydrocarbons.

First, we consider a simple two-component formulation for the oil phase (OBM and reservoir oil) wherein the components are first-contact miscible. A second approach consists of adding water and surfactant to a multi-component OBM invading a formation saturated with multiple hydrocarbon components. Simulations also include presence of irreducible, capillary-bound, and movable water. The dynamic process of OBM invasion causes component concentrations to vary with space and time. In addition, the relative mobility of the oil phase varies during the process of invasion because oil viscosity and oil density are both dependent on component concentrations.

Presence of surfactants in the OBM is simulated with a commercial adaptive-implicit compositional formulation that models the flow of three-phase multi-component fluids in porous media. Simulations of the process of OBM invasion yield two-dimensional spatial distributions of water and oil saturation that are transformed into spatial distributions of electrical resistivity. Subsequently, we simulate the corresponding array-induction measurements assuming axial-symmetric variations of electrical resistivity.

We perform sensitivity analyses on field measurements acquired in a well that penetrates a clastic formation and that includes different values of density and viscosity for mud-filtrate and formation hydrocarbon. These analyses provide evidence of the presence of a high-resistivity region near the borehole wall followed by a low-resistivity annulus close to the non-invaded resistivity region. Such an abnormal annulus is predominantly due to high viscosity contrasts between mud-filtrate and formation oil. The combined simulation of invasion and array-induction logs in the presence of OBM invasion provides a more reliable estimate of water saturation, which, in turn, improves the assessment of in-place hydrocarbon reserves.
Applied Technology Helps Revitalize a Maturing Giant Gas Field: Learnings From the Cleveland Formation's Horizontal-Well Redevelopment Program
Authors: Decker Neil C. , Bumbaugh David B. , Brogdon Ron L. , Gardner David C. , Roberts Stephen P. , Petersen Sean D.
Published: December 2007

The Cleveland formation is a giant tight gas reservoir present across a large area of the northeastern Texas Panhandle and western Oklahoma. The full development potential of the Cleveland has historically been inhibited by variable well performance, inefficient reservoir drainage, and marginal economics. To help address these challenges, operator strategies have shifted in recent years to infill drilling with horizontal wells. This has introduced challenges such as optimizing horizontal well orientation, lateral length, completion type, and the number and length of hydraulic fractures, all within the context of a partially depleted reservoir. To help determine the optimal horizontal well configuration and completion type, operators have become active in acquiring data to improve their understanding of the reservoir and to quantify the variables driving well performance.

Data acquisition includes extensive subsurface mapping, core analysis, well bore stability analysis, open-hole logging, micro seismic acquisition during fracture stimulations, injection-fall-off tests (IFOT), and production decline analysis. Analysis of this data has led to updated material balance calculations and reservoir simulation models, a shift in completion technology, and better quantification of the distribution of the remaining hydrocarbon resource.

Micro seismic data has influenced the selection of a prefered completion design and, along with geomechanical modeling, has improved understanding of fracture behavior and orientation. Similarly, field data has provided indications of generally lower effective gas permeability. In addition, evidence of natural fractures has necessitated their consideration in stimulation design.

Reservoir pressures (inferred from IFOT results), completion data, and reservoir simulation modeling, are helping to guide optimal well placement and completion type of horizontal wells. To further address the economics of drilling horizontal wells, a novel coiled-tubing drilling (CTD) program for reentry into existing vertical wells has been piloted with encouraging initial production results.

In order to more economically exploit this giant field, technological collaboration between operators, who have individually evolved important expertise, has become increasingly important. The integration of data acquisition, application of technology, and collaborative sharing of best practices has resulted in confidence for the re-vitalization of this giant North American gas reservoir.
Successful Applications of Azimuthal Propagation Resistivity for Optimum Well Placement and Reservoir Characterization While Drilling
Authors: Chemali Roland , Hart Eric , Flynn Tracey , Meyer Hal , Helgesen Tron , Kirkwood Andrew , Merchant Abbas , Berle Alf Erik
Published: December 2007

We illustrate the use of a new technology for navigating and characterizing various types of oil reservoirs. Real-time images from Azimuthal Propagation Resistivity measurements provide a "map" of the resistivity patterns up to several meters around the wellbore. In addition, recently developed processing and quantitative interpretation techniques help guide the placement of the well and provide a new perspective of the formation.

When navigating in gas drive reservoirs, the azimuthal resistivity measurement is used to maintain the wellbore at a prescribed distance above the oil-water contact. With its exponential sensitivity to distance, the measurement is able to detect even small changes in the distance to the oil-water interface. In a few instances, the azimuthal information provided by the real-time deep resistivity images indicates probable coning due to offset well production.

Similar principles are applied in high angle drilling of water drive reservoirs. The deep azimuthal information allows the drilling engineer to maintain the wellbore at a prescribed distance immediately below a shale roof. The deep resistivity image from the azimuthal resistivity measurement also makes it easy to distinguish the roof from the occasional approaching shale lens.

Whereas shallower reading LWD image logs (e.g. Gamma Ray and Density) only indicate a geological feature proximal to wellbore, the deep reading azimuthal resistivity measurement can provide geologic structure information at the reservoir scale. Visual displays show the subsurface surrounding the wellbore; quantitative algorithms accurately compute the distance, direction, and apparent dip for reservoir related geological events. A new conductivity unit named "Transverse Siemens" is proposed to help quantify the new azimuthal propagation measurement.
Improving LWD Image and Formation Evaluation by Utilizing Dynamically Corrected Drilling-Derived LWD Depth and Continuous Inclination and Azimuth Measurements
Authors: Bordakov G. A. , Kostin A. V. , Rasmus J. , Heliot D. , Laastad H. , Stockhausen E. J.
Published: December 2007

The paper illustrates the improvements in logging while drilling (LWD) images and subsequent formation evaluation by utilizing a new methodology for depth and survey measurements correction.

LWD depth measurements are often considered inaccurate and therefore not as reliable for well-to-well correlations, correlations to offset data acquired with wireline measurements and formation layer thickness determinations. The reasons for these inaccuracies generally originate from the traditional practice that LWD depth is purposely made equal to the driller's depth, which is a static pipe length measurement made by tape at surface.

There is almost always a difference between the actual measured depth (MD) of the LWD sensor downhole and this static pipe measurement because downhole, the drillpipe is subject to an environment that is not representative of the derrick, such as, varying drilling mechanical conditions and temperature changes. We demonstrate the applications of the method, which allows dynamic driller's depth correction for the effects of drillstring weight, downhole friction, weight on bit, thermal expansion, residual rig heave, and tide.

Another significant inaccuracy source is a standard practice of calculating borehole position from stationary survey points typically taken every 90 ft using minimum curvature method. Neglecting complex borehole shape between survey stations leads to a systematic error in determining the borehole position. We consider using continuous inclination and azimuth measurements along with stationary surveys to correct these errors.

We provide comparisons of LWD images before and after the depth and survey corrections to illustrate how the measurement errors affect formation dips interpreted from the images. We demonstrate how improved accuracy allows filtering out the artifacts together with more decisive and accurate identification of geologic features. We show how using the corrected 3D position allows to improve accuracy of formation thicknesses calculations and therefore to improve reservoir summation results.

As a result we propose a borehole 3D position measurement that is accurate, consistent between wells regardless of rig type or bottomhole assembly (BHA) configuration, and independent of drilling mode. Using this new measurement significantly improves the quality of formation evaluation.
A Comparative Study of Capillary-Pressure-Based Empirical Models for Estimating Absolute Permeability in Tight Gas Sands
Authors: Comisky J. T. , Newsham K. E. , Rushing J. A. , Blasingame T. A.
Published: December 2007

This paper presents the results of a laboratory study where we compare permeability estimates obtained from several mercury-injection capillary-pressure-based models to a set of measured (steady-state), Klinkenberg1-corrected permeability in tight gas sands. We evaluated 63 core samples from several prolific tight gas reservoirs in the U.S. Steady-state permeability and mercury-injection capillary pressure tests were completed on each sample.

The permeability samples range is from 0.0001 mD to 0.2 mD. We review a variety of currently-employed models that are classified as belonging to either Poiseuille or Percolation/ Characteristic Length models. We identify those correlations that are best applied in tight gas sands by quantifying each method's accuracy and precision and force rank each based on error analysis score.
Managing Dual Careers While Working in the Oil and Gas Industry: A Critical Element in Attracting and Retaining Talent
Authors: Chadud N. , Tealdi L. , Howes S. , Sprunt E.
Published: December 2007

Dual career couples are becoming increasingly common in the oil and gas industry. Due to the increasingly frequent demand for mobility, employees are being required to make significant career decisions earlier and earlier in their careers that affect the life and career of their partners. The barriers to achieving a successful career, while simultaneously maintaining a happy relationship with a partner with their own career, are rarely recognized or discussed. Recent worldwide surveys carried out within the Exploration and Production sector demonstrate that work-life balance is becoming an increasingly important consideration in job selection and career decisions. In many countries, private life management ranks high in the pyramid of personal needs. This should not be neglected and significant actions should be taken promptly to overcome the potential for talent loss through migration to other industries and companies. Supporting work-life balance is a critical element in ensuring long-term sustainability of the energy professional workforce. Analysis of surveys of both young and more experienced oil and gas industry professionals is used to recommend actions to avoid the talent loss caused by the difficulties of balancing dual careers and private life with job mobility requirements.
Case Studies Illustrating the Use of Reservoir Simulation Results in the Reserves Estimation Process
Authors: Rietz Dean , Usmani Adnan
Published: December 2007

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

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

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

The 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

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

Liquid 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

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

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

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

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

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

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 (>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

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 (<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.
Why It's Difficult to Learn Lessons: Insights From Decision Theory and Cognitive Science
Authors: Duhon H. J. , Elias J. S.
Published: December 2007

Though engineers and managers routinely express the desire to learn from previous project experience, we typically do not learn effectively from our project experiences. The failure to learn valid and valuable lessons from project experiences can be attributed to a number of cognitive and social factors, which will be discussed below.

Fortunately, there is a great deal of literature in the fields of decision theory and cognitive science that is relevant to the subject. Unfortunately, much of this literature is unknown to most practicing engineers. This paper presents a structured method for identifying learning limits, an introduction to current thinking in areas of knowledge required to implement the method, a summary of the results of applying of the method, and suggestions for improving our ability to learn from project experiences.
Assessing the Past, Present, and Near Future of the Global Energy Market
Authors: Aguilera Roberto F.
Published: December 2007

A new global energy market (GEM) model is developed for examining the global market shares (i.e. the mix) of solids, liquids and gases. The model is successful in matching historical trends for 155 years - from 1850 to 2005 - for solids, liquids and gases. The model also provides a good match of the hydrogen to carbon ratio (which is a good proxy for environmental quality) from 1850 to 2003. Finally, the model matches well the liquid, solid and grid energy sold to consumers in the United Stated since 1900. In all the cases mentioned above, the GEM matches the historical data with coefficients of determination (R2) equal to 0.99.

Given these validations, the GEM is then used to forecast the global energy mix, global hydrogen to carbon ratio, and energy sold to consumers in the US until the year 2030.

Although the past is not always an indication of the future, the good matches observed for historical data lead to the conclusion that the GEM can be used cautiously for evaluating outcomes and opportunities for the near future.
Carbon Management—The Emerging Paradigm for the Oil Industry
Authors: Chakraborty Ashok B.
Published: December 2007

Globally there is concern on the rising concentration of CO2 as it is one of the six Green House Gases (GHG'S) considered responsible for Global warming. Scientifically concluded, the anthropogenic GHG'S are contributing to Global warming. The resultant effect is ‘Climate change’ which is now perceived to be one of the global risk factors, the business faces. The Quantification & Management of Climate related impacts on business, investments, reduction of risk / liability & pursuit of opportunities, is therefore necessary. Along with risk, Carbon emissions (CO2) as a financial commodity currently represent a rapidly growing international market worth over $10 billion. Therefore, it uniquely positions CO2 to leverage opportunities in the carbon emissions trading as well.

Oil & Gas industry is one of major sources for GHG emissions. The O&G activities involve burning, processing, flaring & transporting fossil fuels which emit CO2. It is therefore, imperative that O&G industry need adopt initiatives in mitigating GHG emissions, monitoring & control. The Carbon Management is the key to mitigating CO2 emission. There is an increasing trend amongst oil companies to adopt Carbon Management practices. The challenges include GHG estimation, to internalize externalities, future allocations, caps, low carbon development abatement technologies & the mitigation measures. Globally new developments include energy, fuel consumption & the emissions taxes. There are National control of emission inventories & the forecast, for national planning purposes.

In this paper, development of GHG inventory (& Prediction), GHG accounting system, GHG information system, climate protection policy, protocols, scientific assessments, sustainability reporting, purported benefits to stakeholders, Industry / business, new regulatory requirements , sustainability & economic development, climate change & carbon management opportunities available to the service providers, have been covered. Other issues associated with Climate change briefed are; Scientific complexity, Government policy, International debate and the Competitive pressure.

Carbon Management is going to be a reality in near future for oil companies and the Global trend is in vogue. It is beneficial to adopt proactive approach to be a Competitive, Effective & Credible Organization and realize first mover benefit besides fostering innovation & technology development and influencing global financial systems.

This paper deals with sharing of experience & addresses ‘tomorrow's actions today’.
A Technique for Improving the Accuracy of Wireline Depth Measurements
Authors: Fitzgerald Peter , Pedersen Bengt K.
Published: December 2007

Measurements made with wireline logs are often used as the reference for well depth. However, differences are usually noted between wireline depth ("Logger's Depth") and depth based on the drill pipe tally ("Driller's Depth") or the casing tally, frequently leading to the obvious question: "which one is correct?"

This paper discusses some reasons for these differences, and why the answer to the above question is usually "neither". The reasons why wireline depth may require some environmental corrections are discussed, and a technique for estimating these corrections is presented.

Whilst this may have relatively little impact when considering a single well in isolation, it becomes important when an attempt is made to correlate logs from one well to another, for example to produce field maps or to estimate fluid contacts. As the required depth corrections vary with many factors (for example, well geometry, toolstring weight and cable type used), logs from each well must be corrected independently in order to permit an accurate well to well correlation.

The technique presented is a finite element model that considers changing tension profiles (mostly due to non vertical well profiles, but also well fluid viscosity and changing cable speeds). The model also considers temperature effects on the cable length, which are not trivial. Pressure effects are difficult to evaluate for logging cables, but may also be taken into account if the required parameters are available.

Some examples of these corrections are shown, and the resulting reduction in absolute depth uncertainty is discussed. Finally, reservoir, economic, and operational implications of this work from the perspective of a field operator are presented, as well as recommendations for how to implement depth corrections.
Identifying and Filling Western Europe's Natural-Gas Storage Needs for the Next Decade
Authors: McLeod N. J. , Kelly R. T.
Published: December 2007

During the past 5 years, Western Europe and the U.K. in particular have undergone a sea change in terms of the number of gas storage projects that have been initiated or reached planning/consent stages. This has been largely in response to concerns over the security of gas supply in a market where indigenous gas production is declining at the same time as consumption is on the increase. In addition, EU directives will require member States to maintain a certain minimum volume of gas stocks in some, form of storage (to mitigate against supply interruption).

This paper reviews the outlook for gas storage across Western Europe, and in particular the U.K. which historically has been cushioned from such needs due to its supply of domestic gas from the North Sea. The paper considers the changes that might be expected to happen as indigenous gas is depleted and an ever increasing reliance is placed on imports from potentially less stable areas of the world.

Consideration is given to the drivers that apply to the identification of any gas storage project and in particular the conversion of a depleted natural gas field. Consistent and systematic screening criteria are used to identify the best storage candidates.

The status of the UK's current natural gas field portfolio is considered along with specific examples of fields that may make attractive propositions for conversion over the next 5 15 years. The technical and economic criteria that will play a key role in these decisions are listed and discussed.

Comparison is made between the UK and other countries on a global basis and discussion is included regarding the alternative uses of such depleted fields which may present a (competitive) alternative to the use of depleted fields for gas storage such as CO2 sequestration.