bluuebunny/crossref_metadata_2025 huggingface dataset:
Preventing Hole Enlargement While Drilling Heavy Offshore Oil Reservoirs
Authors: Ferreira M. V. D. , Da Costa F. G. , Campos E. F. , Macedo F. S. , Aragão A. F. L. , Martins A. L.
Published: October 2009

The development of heavy oil fields imposes several challenges for well construction: in order to guarantee minimum flow rates, long horizontals intervals are often required. Long horizontals are associated to long reservoir exposure times which can affect final open hole quality. Rock fluid interaction issues and BHA design directly affect the drilling of sensitive formations, such as non consolidated heavy oil reservoirs.

This article presents initially a comprehensive data analysis of caliper logs in offshore heavy oil wells drilled in Brazil. The analysis correlates hole enlargement with relevant parameters such as fluid type, flow regime and BHA composition. Data sources considered were real time monitoring equipment, logging data and drilling reports. Results indicate that water based fluids and turbulence proved to stimulate hole enlargement and should be avoided.

The study is also supported by a unique experimental work where fluid flow conditions were simulated in a pilot unit where the wellbore was represented by a non consolidated synthetic core saturated with high viscosity oil. For a given flow rate, hole enlargement is monitored with time by a real time CT scanning technique. Experimental results are in agreement with field observations. The role of drillstring composition was not contemplated in the experimental study.
Cemented Ball-Activated Sliding Sleeves Improve Well Economics and Efficiency
Authors: Bozeman Timothy , Degner Dennis
Published: October 2009

This paper examines the effectiveness of a completion technique where ball-activated sliding sleeves (BASS) are cemented into the wellbore. This technique allows operators to change zones between fracture-stimulation treatments by dropping balls from surface, instead of using the conventional pumpdown plug and perforating method. A five-well group completed with this method is compared to its direct offsets that were completed conventionally to draw conclusions. Initial studies show that this completion method reduces the time and cost to complete a horizontal well while yielding production that is equivalent to or better than the offset wells.

Preliminary research shows that the BASS group average 30-day Initial Production (IP) was approximately 25% better than the offset well average, and that the 9-month IP was approximately 33% better than the offset well average. Using the ball-drop completion technique, production increases were accompanied by faster completion times, a reduction in required hydraulic horsepower (HHP), and substantial cost savings. On average, wells that were completed using the cemented BASS showed no cost increase during the drilling phase, and reduced the mechanical completion cost by $20,000 to $40,000 per well when compared to offset wells. The primary efficiency driver during completion is the ability to prepare the well for fracture stimulation and complete multiple stages of fracture stimulation without having to utilize a workover unit. Additional time savings occurs between fracture-stimulation treatments; this method reduces downtime between stages from 3 hours to 20 minutes. This time savings can lead to more efficient use of equipment, which benefits the operator and the pumping company and improves community relations.
Salt Drilling While Underreaming Behaviors Illuminated by Distributed Downhole Measurements
Authors: Kull Bobbie Jo , Duff Richard G. , Clarke Alan J. , Perez Daniel G. , Stuart Simon M.
Published: October 2009

Many developments in the deepwater Gulf of Mexico target reservoirs are below salt sections. As well plans increasingly call for drilling through long salt sections; a common strategy in the Gulf of Mexico is to drill while simultaneously opening the hole with an under-reaming tool. This configuration presents unique dynamic behaviors to the drilling system. Understanding the drilling system is important in order to reduce vibrations and to meet desired run lengths. In the Gulf of Mexico dynamics have limited the effectiveness and life of hole opening tools. Therefore, the identification of drillstring dynamic behavior is critical to efficiently executing well plans that call for under-reaming while drilling.

To study the vibration phenomenon unique to under-reaming while drilling bottomhole assembly dynamics through salt sections the operator employed a unique distributed downhole measurement system which included vibration sensors. The goals of this study were to evaluate the accountability of the real-time MWD and surface data, to illuminate complex dynamics and provide further stimulus for the development and adoption of real-time strategies. The distributed measurement system generated insights in all three areas.

This paper presents examples of specific dynamic behaviors from several deepwater Gulf of Mexico wells, focusing on the drilling phenomenon occurring in salt. Key observations about the development of vibrations while opening the reamer, drilling, drilling transitions and back reaming are given. Attenuation of vibration to the surface is demonstrated. Predrill modeling of bottomhole assemblies was also cross-validated. The impact of cutting structure effectiveness and bottomhole assembly "neutral point management" is also highlighted with examples.
To Gel or Not To Gel?
Authors: Curtice Richard J. , Salas Wendell , Paterniti Melanie
Published: October 2009

Since its commercialization in 1949, hydraulic stimulation has been used on thousands of wells worldwide to increase hydrocarbon production. There are some areas where hydrocarbon production would not be economically viable without this process. The application of hydraulic stimulation has become even more critical when trying to produce hydrocarbons from unconventional reservoirs, such as coalbed methane, shale, and tight gas sands.

Throughout the oil and gas industry, hundreds of millions of dollars have been spent by operators and service companies to develop stimulation-fluid systems that increase proppant-carrying capacity and minimize formation damage. The base fluid has run the gambit of oil, water, foam, alcohol, and sometimes a combination of these. Fluid selection can have a direct bearing on how much proppant can be placed in the formation of interest and have a direct impact on the economics for the operator. In some areas, the associated cost of hydraulic stimulation can be as much as 50% of the overall cost of drilling and completing a well.

Because unconventional reservoirs have become more important in the oil and gas industry, fluid selection has become even more critical because of the nature of the reservoirs. Recently, there has been a change within the industry from using crosslinked gelled-fluids to water systems that use a friction-reducing additive as the fluid of choice when completing wells in unconventional reservoirs, specifically tight-gas sands. These fluid systems are referred to as slickwater.

This paper describes a case history of comparing production data from wells stimulated using crosslinked fluid systems to slickwater fracs in an effort to determine which fluid system gives the best production from an economic standpoint. This paper compares wells from several different operators in the Natural Buttes field, located in northeastern Utah, that were stimulated from 2005 through 2007.
After Closure Analysis for Unconventional Reservoirs and Completion
Authors: Soliman M. Y. , Miranda Carlos , Wang Hong Max
Published: October 2009

Published techniques for after-closure analysis of fracturing data usually assume the presence of a vertical fracture intersecting a vertical well. In addition, these published techniques usually assume that the formation is homogeneous. When the formation is naturally fractured or the well is horizontally intersecting a transverse vertical fracture, those assumptions are obviously violated and the published analysis techniques might not be applicable. Through the use of analytical and numerical solutions and application to actual field data, this paper investigates the analysis of after-closure data for heterogeneous formation, naturally fractured data, CBM, and fractured horizontal well.

This paper briefly reviews the various available techniques for after-closure analysis, pointing out the strengths and weaknesses of each. An analytical solution for injection falloff test for a naturally fractured formation has been developed and is presented. This solution might be used to analyze data for a MiniFrac test in a naturally fractured formation where the fractured has healed. Numerical simulation validated the developed solution for a fracture that has healed. The same numerical simulator was used to expand the solution to a situation where the fracture maintains residual conductivity.

The solution for a MiniFrac test in the case of a transverse fracture is also presented and discussed. Using a numerical simulator, MiniFrac tests are simulated and analyzed for both heterogeneous formations and a fractured horizontal well. Guidelines for analysis of such data have been developed and presented.

Field data are also presented. One case presents a MiniFrac test for a heterogeneous formation. A case for a transverse fracture intersecting a horizontal is also presented and analyzed. A third case for CBM is discussed.
Comprehensive Drilling Model Analyzes BHT Parameters
Authors: Iyoho A. W. , Rask J. H. , Wieseneck J. B. , Grant L. S.
Published: October 2009

Factors that affect downhole temperature while drilling (TWD) were modeled with a comprehensive in-house drilling mechanics and hydraulics model to help explain field observations in a GoM deepwater well. In a long, near-horizontal well section, the TWD from measurement while drilling (MWD) was much hotter than the surrounding formation temperatures, an important issue due to observed dependence of reduced bottom-hole temperature (BHT) and lost-circulation events, and also effects on downhole tools and non-productive time (NPT.)

The model used is an in-house suite of drilling modules capable of modeling hydraulics, torque and drag, drillstring dynamics, and their interactive effects. Heat generation and temperatures are calculated in a coupled manner, by considering factors that include:

Mud-formation heat transfer and mechanical friction of the drillstring against the formation/casing wall; Heat from pressure drop across bit nozzles, and the mechanical rock cutting action of the drillbit; Friction in all drilling situations – making hole, tripping etc, depending on annular clearance; Heat generation from mud-motor operation and operating inefficiencies.

Results indicate that the rotary speed is very important; the higher the RPM, the more the BHT increases. The annular clearance is also a strong factor; the less the clearance, as in casing/liner drilling (CLD) or from tight-clearance downhole tools, the higher the BHT. Other factors in varying degrees of importance are flow rate, mud type, and weight on bit. Results of this work will support on-going attempts at deepwater NPT reduction.
Quantum Effects Imparted by Radio Frequencies as a Stimulation Method of Oil Production
Authors: Becker J. R. , Brown J. Mike
Published: October 2009

Recently a technique using a combination of VHF (very high frequency) and SHF (super high frequency) radio frequencies has been studied both in the laboratory and field, as a means of changing fluid characteristics in crude oil streams. Initial laboratory results showed that at specific frequencies and power levels, wax laden solvent blends and waxy crude oil samples could be altered to carry more wax in solution. These results prompted the concurrent application of these frequencies in producing oil wells to study the effects on production. It was found that from field testing that oil production could be increased and paraffin deposits could be removed by the application of these radio frequencies. We have field tested the device on more than twenty five wells to date with an average increase of oil production of two barrels per day (~25% avg. increase per well). Follow-up well testing by customers has shown that the increase in production is sustained at elevated levels for several days and sometimes weeks and months after one treatment.

The frequencies used by the device are in the range of frequencies used in nuclear magnetic and electron spin resonance spectroscopy. The mode of action is theorized to be the result of changing both the nuclear and electron spin states of molecules such as paraffin waxes and altering the degree of hydrogen bonding and charge induction that result in the aggregation and networking of these wax particles. Gas chromatographic and pour point testing on samples from the treated versus untreated wells show either an increase or decrease of the higher molecular wax fractions and a dramatic decrease in the pour points. This paper presents some of the theory of operation of the device, and laboratory and field data obtained.
Application of Downhole Injection Stress Testing in the Barnett Shale Formation
Authors: Ramakrishnan H. , Waters G. , Boratko E. , Latifzai A. , Bentley D. , Kelley J.
Published: October 2009

Knowledge about minimum in-situ stress gradient of various intervals is essential to accurately predict stimulation treatment pressures, net pressure development and fracture height growth. Though several techniques are available to estimate this stress value, often times the analysis is performed in cased holes using surface measurements of rate and pressure which decreases the accuracy of the estimated stress values due to near wellbore storage effects, perforation to fracture misalignment, etc. Commonly employed pump rates and volumes also result in relatively large fractures which could break out of zone if the formation of interest is thin. Additionally, in vertically complex, low permeability intervals such as shales this can result in long decline periods that evidence multiple closure signatures making interpretation quite difficult. In addition, if reservoirs are being developed with horizontal wells, testing in uncased pilot holes is the only option to derive this information.

This paper discusses the use of downhole injection stress testing to quantify fracture closure stress. Using this technique the injection and measurement of pressure is done downhole at the zone of interest thereby minimizing near wellbore effects and increasing the accuracy of the measurements. Stress testing is possible over very small intervals isolated with openhole packers using a wireline conveyed tool string. The intervals to be tested are determined from open hole logs run prior to testing. Multiple intervals can be stress tested on a single trip into the hole and several injection-decline cycles can be performed at each depth to bracket the range of closure stress for each of the tested intervals. Validation of the interpretation is enhanced via post-injection formation image logging which identifies the fractures created.

Downhole injection stress testing has been performed on multiple wells in the Fort Worth Basin Barnett Shale. Closure stress in various facies within the Barnett Shale and in bounding intervals has been measured. From these tests a better understanding of hydraulic fracture height growth has been acquired. Optimum landing points of horizontal laterals to best control fracture height growth and minimize fracture initiation issues have also been identified.

This paper reviews the tool string utilized in this procedure, the methodology for selecting the intervals to be tested, the testing technique, and the data interpretation procedure.
Transference of Reservoir Uncertainty in Multi SAGD Well Pairs
Authors: Vanegas P. J. W. , Deutsch Clayton V. , Cunha Luciane B.
Published: October 2009

Extensive computational time is required to predict SAGD production performance by thermal reservoir simulation. The common practice is to evaluate the performance of a single well pair and combine the results to pads and projects. Production forecasts for multiple SAGD well pairs simultaneously are computational expensive. At the same time, there is a need to make reservoir management decision in presence of reservoir uncertainty. Accounting for joint uncertainty across the reservoir requires simultaneous management of multiple realizations. Thermal simulators cannot be applied to the transference of such uncertainty to SAGD performance of many well pairs. A proxy model based on the Butler's SAGD theory has been developed to overcome this challenge. The proxy is able to account for reservoir heterogeneity. Modifying factors are included to fit the proxy results to simulation outcomes. The methodology for the transference of the reservoir uncertainty includes: generation of the reservoir uncertainty model using geostatistical tools; ranking the geologic realizations using the Cumulative Steam Oil Ratio (CSOR) calculated by the unfitted proxy. The ranking process is done in a reservoir volume representative of a single well pair: reservoir simulation for the P10 to P90 realizations, fitting the proxy model to simulation results, and assessment of the uncertainty of the SAGD performance by Monte Carlo Simulation (MCS). This methodology was applied to a synthetic example of a pad of eight SAGD well pairs, using 3D geometry and based on hard data from an Athabasca bitumen deposit. The results show the uncertainty in the dynamic performance of SAGD production variables for the entire pad. The results permit decision making under the uncertainty. It is shown that approximate models accounting for uncertainty are better than precise models that cannot be used in stochastic calculations.
Practical Consideration of an Inflow Control Device Application for Reducing Water Production
Authors: Ouyang Liang-Biao
Published: October 2009

Inflow control devices, or ICDs, have been developed to improve well performance and enhance reservoir management by mitigating undesired water and/or gas breakthroughs that often occur due to a variety of factors, including: a). reservoir permeability heterogeneity; b). heel-toe effects - significant wellbore pressure drop from toe to heel; c). different reservoir pressure in different regions penetrated by a well.

Success of an ICD completion relies heavily on appropriate design of the completion. Several key issues that should be addressed in designing an ICD completion have been identified and their impacts on performance of a well equipped with ICDs will be elaborated through a couple of case studies after a brief introduction of the three major types of inflow control devices (ICD). Practical guidelines for applying an ICD completion for reducing water production will also be shared.

Several important observations have been achieved through this study: Appropriate design and planning for an ICD completion requires: a). good knowledge of reservoir and geology, such as permeability, porosity, reservoir pressure, as well as oil/water saturation distribution, etc; b). accurate modeling of the near wellbore fluid flow and flow in the completions; c). reasonable account for the change of reservoir condition over time - possible coupling between completion simulation software with a reservoir simulator is preferred.Zonal isolation plays a critical role in the success of an ICD completion, especially in terms of water production reduction.ICDs have been mainly developed to minimize toe-heel effects and balance inflow. Under certain circumstances, nontrivial water production may be anticipated from a well from day one of the well production. An ICD is not expected to trim much of water production from this type of well since water is already there, unless additional measures are taken to cut down water production.There are potential approaches for minimizing water production in well with ICD completion, such as: ✓Change well trajectory to avoid high water saturation region(s);✓Apply ICDs with efficient phase filtering capability;✓Block water production with efficient zonal isolation.A reasonable design of ICD completion may have promising potential to cut water production as long as good zonal isolation across layers and sections exists; however, water production may also be cut with other completion options without ICD under the circumstances.
Scale Prevention Application of a Chemical Technology That Has Been Effectively and Economically Applied to a 420°F, 13,500-Ft-Deep, Gulf of Mexico (GOM) Well to Prevent Lead and Zinc Sulfide Deposition
Authors: Darby Greg , Uhlig Doug , Steckler Jason , Martin John
Published: October 2009

Water production from a deep, hot Gulf of Mexico well has led to the problematic deposition of lead and zinc scales in the near wellbore area and perforation interval. The well completion contains Incoloy 825 metallurgy. The exotic scale, high temperature, and exotic metallurgy contributed to expensive well repairs and limited prevention options. Prior to the squeeze application that is the subject of this paper, the subject well was experiencing rapid production decline which required frequent and uneconomical acid dumps and mechanical milling. This paper describes a novel technology that has prevented deposition of the scale.

The application described has been used in the Mobile Bay area of the Gulf of Mexico. A well recently squeezed with a scale inhibitor developed for use at high temperatures (>420°F). Tube blocking lab testing showed it to be effective scale inhibitor for preventing sulfide scales. The squeeze application was pumped as a 20% active pill in KCl and displaced with nitrogen. Four treatments have been applied to the well over the last 13 months.

The well was quickly, economically, and successfully treated to prevent the scale. Scale inhibitor residuals remain high six months after the second treatment. Two gauge-ring run with wire-line indicates scale-free tubing. Production rates and pressures have improved from pre-treatment values. It is the intent to continue monitoring residuals and re-squeeze the well when residuals drop below the effective level.

The primary benefits of the chemical squeeze are long-term production and reduced mechanical intervention. Other benefits include the potential elimination of surface treatment equipment, reduced use of acid, ease of monitoring, and proven success. This novel technology brings an economic and technologically superior solution to the problem of high-temperature, exotic scale management in GoM wells.
Application of Chemical Concentrates to Well Annulus via Patented High Quality, Low Liquid Volume Foam Application
Authors: Darby Greg , Brown J. Mike
Published: October 2009

Gas and water production from CBM wells in Southwest Virginia has led to problematic deposition of mineral scales. Calcium carbonate essentially cements the production casing and tubing together, making well repairs time-consuming, difficult, and costly. In some areas, work-over operations to remove the mineral scale deposition exceed $165,000 and several weeks per well. This paper will describe a novel technology that applies acid via foamed liquid to free the tubing at a fraction of the time and cost compared with traditional means.

The applications described in this paper have been in the Southwest Virginia area. Twelve unproductive CBM wells were treated with a foamed acid that successfully, economically and quickly helped free stuck tubing. The technology uses nitrogen gas to help generate stable, self-supporting foam from a liquid acid and foamer additive. The application is made to the annulus from a truck-mounted, purpose-built skid that contains the chemical, nitrogen, pump, and foam generation equipment. Pumping foamed acid results in coverage of a larger area of the annulus compared with pumping liquid acid.

A foamed acid treatment on day one, followed by a water dump on day two, has lead to the successful pulling of stuck tubing. In addition to freeing the tubing, treated wells have provided the operator with increased gas production compared to traditional remediation methods. When treated regularly (treatment intervals range between 60-180 days), the wells maintain a steady rate of gas production.

The primary benefit of a foamed chemical application is the nearly universal coverage of the annular space. Other benefits are the elimination of the need for surface treatment equipment, low volumes of chemical required, ease of monitoring, and the ease and safety of application. This novel technology brings an economic and technologically superior solution to the problem of scale management.
Determining Trapped Gas in Foam From CT Images
Authors: Kil R. A. , Nguyen Q. P. , Rossen W. R.
Published: October 2009

Foam is used worldwide on a daily basis for acid diversion in well stimulation, on a pilot basis for redirecting gas flow in enhanced oil recovery (EOR), maintaining mobility control in surfactant EOR and improving the efficiency of surfactant-based aquifer remediation. Gas trapping by foam is a key mechanism of foam mobility and foam effectiveness in all these applications.

Previous studies have attempted to quantify the extent of gas trapping by injecting a tracer gas within the foam and then fitting the effluent profile to a one-dimensional (1D) capacitance model. In this model, at any given axial position along the core, all flowing gas and all trapped gas are each at a single tracer concentration. CT images of experiments using Xenon tracer show that this assumption is not accurate: trapped gas near flowing gas comes rapidly to equilibrium with flowing gas, long before tracer diffuses into trapped gas further away.

We introduce a method that uses the CT images directly to estimate flowing-gas fraction. In the CT images, tracer advances in many small channels and diffuses outwards into surrounding regions of trapped gas a few mm in diameter. The difference between the higher tracer concentration at the center of these channels and the lower concentration at the edge can be related to diffusion coefficient of the tracer and the flowing-gas fraction within the channel. For the CT images of Xe tracer in one experiment, this method gives flowing-gas fractions one or two orders of magnitude smaller than that estimated using the 1D capacitance model. The model can be used to estimate flowing-gas fraction in different regions of a core in spite of different average gas velocities in the different regions.
Determination of Rock Strength Using Advanced Sonic Log Interpretation Techniques
Authors: Sayers Colin , Russell Charles , Pelorosso Mauro , Adachi Jose , Pastor Jorge , Singh Vasudev , Tagbor Kwasi , Hooyman Patrick
Published: October 2009

Analysis and prediction of geomechanical problems is important for the success of drilling, completion, and production operations, and requires knowledge of rock strength, pore pressure and in-situ stress. Geomechanical problems encountered while drilling include wellbore stability and fracturing of the formation, and may lead to financial loss due to loss of drilling fluid, well control events (kicks), stuck pipe, extra casing strings and sidetracks. Examples of geomechanical problems due to reservoir stress changes occurring during production include reservoir compaction, surface subsidence, casing deformation and failure, sanding, etc. The information needed to assess the impact of geomechanical problems on field development can be captured by building a Mechanical Earth Model (MEM) that includes details of the in-situ stresses, rock failure mechanisms, rock mechanical parameters, geologic structure, stratigraphy and well geometry. The workflow for building a Mechanical Earth Model (MEM) along a well trajectory based on logs and drilling data is illustrated for the case of a deviated well drilled through deepwater Gulf of Mexico channel sands. Once constructed, a MEM can be used to identify geomechanical problems and formulate contingency plans for mitigation before future wells are drilled. The stress field in the vicinity of a well is perturbed by the physical operation of drilling the well. This process may result in formation damage or alteration of the rock properties resulting in changes in acoustic velocity in the vicinity of the well. The constructed MEM uses the variation in the fast and slow shear wave velocities as functions of the distance from the borehole to determine the variation in rock strength along the well. The results of mechanical rock properties measured from cores in an independent study are found to be in good agreement with the rock strength determined from the sonic log measurements.
Methodology for Integrated Reserves Management: Providing Regulatory Compliance and Improving Decision Making
Authors: Virine Lev , MacDonald Doug
Published: October 2009

Effective corporate reserves management systems allow petroleum companies not only to track reserves and provide input for reporting to regulators, but also to serve as a decision support system. Implementation of such reserves management systems comes with a number of challenges. Regulatory bodies, including the U.S. Security Exchange Commission (SEC), require proper categorization of reserves based on evaluating whether the volumes can be economically recovered in a timely manner. The reserves management system should be able to provide technical and economic volumes based on up-to-date prices, capture and analyze uncertainties in the reserves volumes, provide secure data access and data archiving, and implement an approval and audit process.

To address these challenges, a methodology for integrated reserves management was developed. This methodology comprises three integrated processes: data management, which ensures fast and secure access to reservoir data; economic and technical volume calculation; and a flexible reporting process. The proposed workflow includes the following steps. Reservoirs, as well as prospects, are organized within a corporate hierarchy. In accordance with SEC regulations and SPE/WPC Petroleum Resources Management System guidelines, the data management process captures proven, probable, and possible reserves, as well as discovered and undiscovered resources for different petroleum products and companies with different working interests. Each category of each reservoir is associated with an economic case that contains information about costs, prices, and the fiscal regime. Economic volumes can be calculated based on the results of economic evaluations of the reserves. Uncertainties in reservoir data are captured using multiple scenarios for each reservoir and category. A regional pricing mechanism allows for updating prices for all economic cases at a particular level of the corporate hierarchy. All changes to the economic results data would be recorded and require approval.

This methodology for integrated reserves management provides for the comprehensive management of reserves data in the organization. It allows accurate reserves tracking and reporting to regulatory bodies by mitigating the negative effect of motivational biases. Through a consistent set of categories, scenarios, products, and companies, the proposed workflow provides evaluation and tracking of both technical and economic volumes.
A Game Theoretic Approach to Conflicting and Evolving Stakeholder Preferences in the E&P Industry
Authors: Willigers B. J. A. , Bratvold R. B. , Hausken K.
Published: October 2009

In the high-risk E&P industry, the profit of each stakeholder depends on the strategies of all. The optimal choice for one player may not be optimal for other players, who may opt to prevent it. These characteristics suggest using game theory to model decision situation in the E&P industry. In a business dominated by joint ventures and tight governmental regulation, an understanding of the interests and influence of all stakeholders is particularly important. Although the E&P industry is accustomed to develop complex economic models to obtain insight into the commercial attractiveness of joint ventures, the influence of other stakeholders is often ignored. Each stakeholder must decide how much to invest, in which sequence to make decisions, whether to make decisions before or after the other stakeholders, which decisions to make before versus after technological and organizational uncertainty is resolved, whether to accept or block the designation of one stakeholder as dominant, and whether to accept or block hub placement within one of multiple oil fields. A joint development program of a portfolio of gas fields and its gas processing and export facility has been analyzed using tools from game theory. The focus is on which infrastructure to develop and when. Players’ preferences are functions of equity stakes and expected reserve sizes of the prospects. The analysis provides insight into the preferred development options of the individual players, how preferences change as uncertainty gets resolved, and how much individual players are to gain or lose if certain investment decisions are made. The analysis allows a player (1) to identify under what conditions its objectives are aligned with fellow players and (2) to quantify the maximum amount it can pay to gain support from its fellow players.
Practical Portfolio Simulation: Determining the Precision of a Probability Distribution of a Large Asset Portfolio When the Underlying Project Economics are Captured by a Small Number of Discrete Scenarios
Authors: Willigers B. J. A.
Published: October 2009

One of the great successes of modern financial risk modelling is the application of computing technology to simulate complex continuous probability distributions associated with the value metrics of real-life assets. The Monte Carlo simulation technique is the best known example and is widely applied by economists in the E&P industry. However a Monte Carlo simulation in which project economics are aggregated into a large asset portfolio is rarely undertaken. The main reason is that present computing systems cannot handle the vast amounts of data generated in a Monte Carlo simulation of a large asset portfolio.

A pragmatic solution for this issue might be to approximate the continuous distribution of feasible project outcomes using a small number of probability-weighted discrete scenarios. In a corporate portfolio simulation, a project sample would be drawn from these discrete distributions as opposed to the original continuous distributions. If either a global assumption needs revision or a single asset requires recalculating, the economics of a relatively small number of scenarios would be computed. Thus, there is no need to store or recalculate a large number of outcomes (typically more then 2,000) for each project, as would be required in a conventional Monte Carlo simulation.

A prerequisite for this approach is that the frequently skewed and complex continuous probability distributions of each of the assets can precisely be described by a small number of scenarios. This study documents the level of precision that can be achieved using Swanson's rule and variations thereof. Our analyses suggest that if the P50 is at least 33% greater than the P10, the simulated portfolio mean and standard deviation are within 5% and 15% of the actual values, respectively. The approximation of the lower end of the distribution, i.e., the downside risk of a portfolio, is within 4% even for an extremely asymmetric lognormal distribution.

The proposed portfolio simulation methodology addresses the largely unmet need of corporate managers to improve their understanding of key risk and value drivers and their impact on the performance of a corporate asset portfolio.
A Mechanistic Model for Gas/Liquid Flow in Upward Vertical Annuli
Authors: Yu T. T. , Zhang H.-Q. , Li M. X. , Sarica C.
Published: October 2009

In this study, a mechanistic model is developed to predict flow patterns, pressure gradient and liquid holdup for gas-liquid flow in upward vertical annuli. The flow pattern transition model consists of modified Zhang et al. (2003a) unified model for dispersed bubble flow and annular flow pattern transitions, Caetano (1986) model for bubbly flow transition and modified Kaya et al. (2001) model for slug to churn flow transition. The hydrodynamic models are developed based on the dynamics of slug flow and the film zone is used as the control volume. The two liquid films are taken into account in the annulus slug flow and annular flow model developments. The churn flow model is developed based on the Zhang et al. unified model for pipe flow by using a much shorter slug length.
Real Time Response to Field Corrosion Data Through an Electronic Client Portal Interface Leads to Decreased Well Failures
Authors: Higgins Rocky , Lamb Jim , Szymczak Steve
Published: October 2009

Simple and economical solutions are best affected when open communication exists. In this case study an operator and a specialty chemical supplier worked to reduce both microbial influenced corrosion (MIC) and CO2 corrosion. The process of corrosion mitigation was greatly enhanced through the use of a client portal (CP) by which real time data was released onto the portal, an operating engineer diagnosed the data and remedial measures were taken to reduce the corrosion failure rates.

The number of wells (>3800) and the amount of gas production (<80 mscfd) dictated the use of an economical electronic tool that could hold all pertinent data and manipulate the data in order to make valid assumptions. The CP allowed the field technical staff to input corrosion and failure data directly into the CP database. This would be coupled with an e-mail notification to the project engineer. This e-mail would give an overview of the data analysis as well as a recommendation and cost for remedial action. The engineer could immediately make a cost-benefit decision and respond to the technician. Subsequent monitoring tracked the progress in arresting corrosion.

Those 3800 gas wells produce from depths of 5200 to 8000 ft. Total well tubing failure rates stood at 0.125 FPWY (failures per well per year). This was equal to 475 failures per year. After 18 months of a focused corrosion inhibition program managed through the CP, the tubing failure rate dropped 70% to 0.0375 FPWY. This is a reduction of 330 well failures per year. This resulted in workover cost savings in the millions of dollars per year.

Knowing the problem, arriving at a solution and implementing a remedial program make up the core effort of production engineers and service companies. In this case study, sound problem identification and real time remedial actions served to reduce workovers and related costs. This resulted in a production increase due to the decrease in downtime for workovers. By integrating the CP into the problem solving process, the operator saw improved results more quickly.
Effect of Eccentricity and Rotation on Annular Frictional Pressure Losses With Standoff Devices
Authors: Pratap Singh Ajay , Samuel Robello
Published: October 2009

Pressure drop estimates are critical for components of the drilling process. During drilling and cementing operations, many stand-off devices, such as centralizers, reamers, and turbulators, are widely used. Few studies have explored the pressure losses arising from these attached devices in the drillstring or casing string with eccentricity and rotation, and these pressure losses are assumed to be negligible. Eccentricity between the wellbore and the stand-off devices, rotation, and the complicated geometrical designs of these devices, which relatively irregular and complicated, increase the complexity of the frictional pressure loss calculations. This study examines the effect of the various geometrical parameters of the commonly used devices, eccentricity, and rotation of the devices, flow rate, and rheological properties on the annular pressure loss using c computational fluid dynamics (CFD). For laminar flow, the 3D Navier-Stokes equation is used. The turbulent flow is based on k- model. This paper presents the results of the study of the alteration and effects of various rheology models on the flow profile and annular pressure losses. This parametric study explores the importance of eccentricity and device rotation and presents a simple set of comprehensive equations and guidelines to calculate the pressure losses for commonly used devices. These equations and guidelines are useful in the determination of the number of devices and of their optimum placement in the string. Although the annular pressure loss against these devices may be negligible, at times incremental pressures from the large number of stand-off devices or in a narrow clearance extended reach wells are potentially detrimental to the well. This paper also presents case studies in which the pressure losses were not negligible and stresses the importance of considering the pressure losses encountered using these devices.
A Second-Order Fast-Forward Model for a Gamma-Gamma Density Logging Tool
Authors: Zhou Tong , Miles Jeffrey R. , Case Charles R. , Chiaramonte Joseph M. , Ellis Darwin V.
Published: October 2009

A fast-forward (FF) model for density logging is an essential element for inversion techniques, which may be performed with density data alone or jointly with other measurements. Such models must be both fast and accurate to be of value in the log interpretation process. The environment of high-angle or horizontal (HA/HZ) wells presents a scenario in which forward models have particular promise.

In the 1980s, Watson (1984) developed the technique of differential sensitivity functions to rapidly predict the response of a density logging tool. However, the accuracy of this technique is modest because of the limitations inherent in its linear approximation. In this work, we extend the density sensitivity technique to a second-order approximation. A critical component of this model is the second-order sensitivity functions, which are challenging to calculate. With the aid of the perturbation feature in the MCNP5 code, we use elements of the sensitivity functions at both the first and second orders to approximate the second-order dependences.

We calibrate the model in fully detailed MCNP (Monte Carlo N-particle) simulations of the EcoScope* LWD tool response for a wide range of borehole conditions covering formation electron densities from 1.5 to 3.0 g/cm3; drilling fluids of water, light mud, and heavy barite mud; and standoff values from 0 to 1 in. The maximum deviations between the forward model predictions and MCNP simulations in these diverse borehole conditions are 0.02 g/cm3 for the long-spacing (LS) electron density, 0.03 g/cm3 for the short-spacing (SS) electron density, and 0.04 g/cm3 for the compensated electron density. This combination of accuracy and versatility is a dramatic improvement over the performance of linear sensitivity techniques. We benchmark the model in a simulated HA/HZ well environment and demonstrate performance that is roughly consistent with the calibration. The speed of the improved forward model is almost equivalent to that of the original sensitivity function technique and is six orders of magnitude faster than the Monte Carlo data calculations.
Simulation of Liquid Unloading from a Gas Well with Coiled Tubing Using a Transient Software
Authors: Salim P. , Li J.
Published: October 2009

Unloading gas wells is one of the most common applications for coiled tubing (CT). Despite the large number of jobs completed, fundamental questions about the optimum gas lift rate, run-in-hole speed and how much nitrogen is required remain. This is because the unloading process is not steady state, and the commonly used CT computer simulations can only model steady state flow.

This paper describes transient software that has been developed and used to determine the nitrogen volume and cleaning time required when optimizing the process of liquid unloading from a gas well with CT.

Based on experimental test results with a full scale flow loop, a critical gas velocity model was developed. This model determines how much liquid can be lifted for a given gas rate under varying operating conditions. It also determines the minimum gas rate required for complete liquid unloading. Several examples are presented which illustrate the transient characteristics of the liquid unloading process. A few field cases illustrate the benefits of using the transient model and some problems with conventional design methods.
Injectivity and Gravity Segregation in WAG and SWAG Enhanced Oil Recovery
Authors: Faisal A. , Bisdom K. , Zhumabek B. , Mojaddam Zadeh A. , Rossen W. R.
Published: October 2009

Gas-injection enhanced oil recovery can recover nearly all residual oil where the gas sweeps. Sweep efficiency in these processes is often poor, in large part because of gravity override of gas. Stone and Jenkins presented a model for gravity override in homogeneous reservoirs, showing that the distance gas and water travel before segregation depends directly on injection rate. In cases where injection pressure is limiting, injectivity is key to overcoming gravity override.

Stone assumed continuous co-injection of gas and water as a model for WAG, contending that this is valid as long as slugs mix near the well. This model for co-injection can be extended to relate segregation distance for co-injection processes directly to injection pressure. Injectivity depends on saturations very near the well, however. Therefore, where injection pressure is limiting, this model is pessimistic because injectivity in WAG is greater than in co-injection.

We investigate the increase in injectivity possible with WAG compared to co-injection in 1D and 2D, and the implications for gravity override in 2D, using a range of models for gas and water relative permeabilities. We confirm that the greater injectivity of WAG improves vertical sweep compared to Stone's model when injection pressure is limiting. The greatest improvements occur when slugs violate Stone's assumption: that is, they are too large to mix fully near the well. The increase in injectivity over co-injection is greater for foam than for WAG without foam, because foam has much lower mobility when gas and water flow together.

A similar benefit occurs for "simultaneous water and gas" (SWAG) injection from a single vertical well with water injected higher in the formation than gas. There is a modest benefit to injectivity of injecting water above gas, but far smaller for water-gas flow than that estimated for foam in a previous study.