bluuebunny/crossref_metadata_2025_split huggingface dataset:
To Gel or Not To Gel?
Authors: Curtice Richard J. , Salas Wendell , Paterniti Melanie 
Published: October 2009

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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 (&gt;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

Abstract
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

AbstractFoam 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

Abstract
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.