bluuebunny/crossref_metadata_2025 huggingface dataset:
Wellbore Tortuosity, Torsion, Drilling Indices, and Energy: What do They have to do with Well Path Design?
Authors: Samuel Robello , Liu Xiushan
Published: October 2009

Borehole quality is generally related to the "smoothness" of the wellbore which manifests in a number of ways, all tied to the efficiency of the drilling process and drilling and well completion cost. Presently, several parameters, such as wellbore tortuosity, curvature, torsion, and various drilling indices, are used to quantify the well path or to estimate the difficulty of drilling a smooth well. Furthermore, there is no clear criterion for defining the quality of the wellbore. Drilling indices describe the quality of the hole more subjectively, rather than quantify the hole qualitatively. In some cases, they are used solely as a measure of how difficult it is to drill the well, rather than how smoothly it was drilled.

Another important parameter that is neglected in the calculations is wellbore torsion. Wellbore torsion depicts the rotating rate of the binormal vector with respect to curved length, or the measure of the rate at which the osculating plane changes its direction. It ensures a smooth well path and reduces the drag and torque in extended reach and ultra-extended reach wells. Because there is no industry standard for quantifying these parameters, a great deal of confusion exists between them, and they are used interchangeably and loosely without any proper substantiation and understanding. This paper provides the details of these parameters, as well as a clear definition and context in which they can be used. The simple guidelines are presented with several example calculations. This paper also provides methods for evaluating these parameters applied on a smooth well path in relative and absolute terms. An additional mathematical criterion based on non-linear curve modeling of a thin elastic beam known as the minimum energy for measuring the borehole quality is presented in this paper.
Depletion-induced Stress Changes in a HPHT Reservoir: Calibration and Verification of a Full-field Geomechanical Model
Authors: Hettema M. H. H. , Bostrøm B. , Pedersen E. S.
Published: October 2009

The Kvitebjørn field is a high pressure and high temperature gas-condensate field offshore Norway seated at a depth of 4000 meters. The field is produced by pressure depletion and therefore many geomechanical risks are at hand. In order to be able to forecast the geomechanical risks a full three-dimensional finite element model of the Kvitebjørn field has been built. We use four types of field measurements for initialisation, calibration and verification of the model:

Surface subsidence measurements at the platform location In-situ compaction measurements from radio-active marker loggin Material properties from core and log measurements Stress measurements from extended leak-off tests

Repeated compaction logging and global positioning measurements are used to calibrate the deformations at the surface and the reservoir level. The geomechanical model is populated by material properties based on core and log measurements. Four extended leak-off tests have been performed at different stages of reservoir depletion. The main application of the model is to determine and predict the depletion-induced stress changes for the entire Kvitebjørn field, to assess geomechanical risks related to infill drilling and collapse of production wells. It is concluded that the calibration and verification of the geomechanical model giving confidence in the prediction of the depletion-induced stress changes and the related geomechanical consequences.
How to Prevent Loss of Zonal Isolation Through a Comprehensive Analysis of Micro-Annulus Formation
Authors: Bois A. -P. , Garnier A. , Rodot F. , Saint-Marc J. , Aimard N.
Published: October 2009

Micro-annuli at the well cement sheath's interfaces may result in loss of zonal isolation, which is the source of many problems, such as sustainable casing pressures, cross flows between reservoirs or any undesirable flow behind casing. They are commonly explained by cement volume variations during hydration (chemical shrinkage/expansion) or by contraction of the casing due to a decrease in mud density/temperature as these could create a gap if cement cannot follow induced deformations. However, these modes are not sufficient to predict all possible types of micro-annuli encountered in oil and gas wells, meaning that other modes have been missed.

This paper presents a comprehensive mechanistic analysis of micro-annulus formation to highlight the forgotten modes, to explain them, to detail under which conditions they can appear, and to present counter measures to prevent them. It is based on both theoretical and experimental evidences and takes into account most features that characterize cement after it has been placed, including cement volume variations during hydration, cement heat production during hydration, mud density and temperature variations, cement thermo-poro-elasto-plastic behavior during and after hydration, formation thermo-poro-elasto-plastic behavior, and formation initial state of stress.
Model-Based Optimisation of a Gas Production System—The BP Trinidad Field Optimiser
Authors: Ramdial A. M. , Hudson N. H. , Pike R. G. , Rodriguez J. C. , Stratman M. S. , Sama S. S.
Published: October 2009

Oil and gas production facilities are being pushed to their limits to achieve maximum throughput in a period of global economic uncertainty. Cost pressures continue and balancing costs, throughput and maintaining safety remain the unending challenges. This paper and presentation will address a real example of a gas company that has leveraged real-time data with engineering models to manage a complex production system.

It will address these business challenges: How to turn real-time data into actionable information (historized process settings, well test data, etc).How to encourage cross discipline communication by integrating sub-sea, offshore, and onshore facilities.Understanding the impact of field and process constraints together in production potentials and capacity utilization, e.g.:Available separation and transportation capacity.Pipeline back-pressure effects.Wells operational limitations.Onshore treatment constraints (condensate RVP and water contents, capacity of installed stabilization units, etc).Meeting contractual obligations in the most profitable way (e.g. produce the nominated gas quantities in a way that maximizes the condensates revenue stream).Reacting to system upsets and planned equipment outages.In depth understanding of the potential of new field developments and of the required changes in the operating philosophies to maximize the value of the investments.

The Asset system has been tested in a number of real production situations where it has helped to: Pinpoint process behaviors that can be turned into an opportunity for economic improvement,Identify process bottlenecks under various different production scenarios,Co-relate offshore and onshore process constraints to find true overall optimums, andIdentify potential oil production increases
Corporate Venture Capital as a Conduit for Early Adoption of Emerging Technology: A Decade of Experience
Authors: Unneland Trond , Hanten John
Published: October 2009

A continuous challenge in the petroleum industry is to identify and rapidly implement new technologies into field operations to increase production, improve employee productivity and lower costs. Utilizing new world class technology is critical as the industry moves towards more complex environments. To support this, a Chevron corporate strategy is to leverage technology to deliver superior performance and growth. A range of tools are available to achieve this, such as internal R&D, joint ventures and collaboration with academia & service companies. A less traditional method in the petroleum industry is to use corporate venture capital (VC) as a tool to gain access to world class technology. This paper covers a decade of Chevron venture capital experience, including justification for corporate VC investments, how success is measured, financial and strategic yield, investment criteria, governance, partnerships, track record and portfolio highlights. In the paper, several technology transfer success stories are given including the financial and operational value they created for the Chevron business units. The investments cover such diverse technology areas as artificial lift, seismic monitoring, deep water technology, wind power, and high end computing for reservoir simulation.
Modeling Multiphase Wax Deposition in Submarine Pipelines After Shut-In
Authors: Villazon G. Michel , Civan F.
Published: October 2009

Rigorous modeling of wax deposition in submarine oil pipelines undergoing a cooling process after shut-in is developed. Relevant mechanisms of wax deposition are described by accurate approaches. Fraction of wax precipitated under various conditions is estimated by an improved correlation and validated using experimental data. It is proven that consideration of a moving boundary between waxy gel and liquid oil is unnecessary and consideration of wax/oil mixtures as a continuously varying multiphase system is more effective.
Combining Drilling and Evaluation Technology in Remote Operations Increases Reliability
Authors: Thorsen Arve K. , Vargervik Elin , Nygaard Vebjorn
Published: October 2009

Over the past decade several attempts and methods have been applied to ensure remote operations—from moving operations directly from offshore to onshore to a complete redefinition of work processes and responsibilities. This paper demonstrates how a different work methodology onshore improves the reliability in the total drilling and logging while drilling (LWD) operation, focusing on combining drilling and evaluation work processes and technologies.

This paper presents several cases where combining drilling optimization with LWD formation evaluation greatly enhances the understanding of the subsurface environment. The main goal is to optimize the drilling progress with regards to hole condition and reliability combined with optimum well placement.

The elements involved in this process include:

Use of downhole drilling dynamics measurements and interpretation of these to determine required action to reduce any damage to the downhole sensors and to ensure the energy is used to penetrate new formation. Use of LWD data both for understanding the overall drilling regime and for optimum well placement.

In combination with LWD formation evaluation, any changes in the rock penetrated are instantly taken into the drilling optimization procedure, and parameters are then optimized to maintain maximum progress. In this way, the guesswork about changes in the rock properties is eliminated, and the correct action is implemented instantly.

In addition to the downhole technology, the work flow procedures and distribution of responsibilities throughout the team will be explained. Strong collaboration between the different team members is essential to make this process work.
Holistic Design of Cement Systems to Survive CO2 Environment
Authors: Moroni N. , Santra A. , Ravi K. , Hunter W.
Published: October 2009

Cement systems that can survive in the CO2 environment are needed in various applications. Examples of these applications include: 1) producers: CO2 in the reservoir is produced along with the hydrocarbons, 2) injectors: CO2 is injected for sequestration and/or enhanced oil recovery, and 3) producers and injectors: produced CO2 can subsequently be injected for the purpose of enhanced oil recovery/sequestration.

However, the carbonation of Portland cement is a well-documented, thermodynamically favorable process. When CO2 or carbonic acid comes in contact with Portland cement, it initially reacts with it to form water-insoluble calcium carbonate. Longer term, the presence of water dissolved with CO2 (or carbonic acid), if allowed to contact the cement sheath, can dissolve the calcium carbonate to bi-carbonate, which then could be displaced if a flow channel were to be present or formed during the life of the well. This can threaten long-term effective zonal isolation.

A dual level solution is required to effectively address this challenge. As a first level, the potential for CO2 to enter the cemented annulus and contact the cement sheath is minimized, by placing the cement slurry in the entire annulus, reducing the permeability and endowing the set sheath with the properties necessary to withstand the well events. The second level involves reducing the amount of material in the set cement sheath that is reactive to CO2. This holistic approach has worked well in practice. Both the physical and chemical integrity of the cement sheath is addressed using this approach.

Following the design logic described above, a cement system with improved resistance to CO2 environments was created by 1) designing a reduced-permeability cement sheath to withstand well operations with low cement hydration volume shrinkage and 2) optimizing the cement slurry formulation so that its hydration products have a lower amount of materials that are reactive to CO2. This cement system was then tested in the laboratory under expected in situ conditions and optimized for different well situations before placement in the field.

The cement systems have been successfully placed in anumber of wells and these wells are all operating as required with no loss of zonal isolation reported. The design approach, laboratory test procedure and results from laboratory and field are presented and discussed in this paper.
More Accurate Gas Viscosity Correlation for Use at HPHT Conditions Ensures Better Reserves Estimation
Authors: Davani Ehsan , Ling Kegang , Teodoriu Catalin , McCain William D. , Falcone Gioia
Published: October 2009

High-pressure and high-temperature (HPHT) gas reservoirs are defined as having pressures greater than 10,000 psia and temperatures over 300°F. Modeling the performance of these unconventional reservoirs requires the understanding of gas behavior at elevated pressure and temperature. An important fluid property is gas viscosity, as it is used to model the gas mobility in the reservoir that can have a significant impact on reserves estimation during field development planning. Accurate measurements of gas viscosity at HPHT conditions are both extremely difficult and expensive. Thus, this fluid property is typically estimated from published correlations that are based on laboratory data. Unfortunately, the correlations available today do not have a sufficiently broad range of applicability in terms of pressure and temperature, and so their accuracy may be doubtful for the prediction of gas viscosity at HPHT conditions.

This paper reviews the databases of hydrocarbon gas viscosity that are available in the public domain, and discusses the validity of published gas viscosity correlations based on their applicability range.

A falling body viscometer was used in this research to measure the HPHT gas viscosity in the laboratory. The instrument was calibrated with nitrogen and then, to represent reservoir gas behavior more faithfully, pure methane was used. The subsequent measured data, recorded over a wide range of pressure and temperature, was then used to evaluate the reliability of the most commonly used correlations in the petroleum industry. The results of the comparison are presented here and suggest that at pressures higher than 8000 psia; the laboratory measurements drift from the National Institute of Standards and Technology (NIST) values by up to 7.48%.

Finally, a sensitivity analysis was performed to assess the effect of gas viscosity estimation errors on the overall gas recovery from a synthetic HPHT reservoir, using numerical reservoir simulations. The result shows that a −10 % error in gas viscosity can produce an 8.22% error in estimated cumulative gas production, and a +10% error in gas viscosity can lead to a 5.5% error in cumulative production.

These preliminary results indicate that the accuracy of gas viscosity estimation can have a significant impact on reserves evaluation.
Selection Criteria for Artificial Lift System Based on the Mechanical Limits: Case Study of Golfo San Jorge Basin
Authors: Hirschfeldt Clemente Marcelo , Ruiz Rodrigo Ariel
Published: October 2009

The Golfo San Jorge basin is the oldest productive basin of Argentina, and is located in south Patagonia. With 12,630 active oil wells, the basin produces 269,937 bpd of oil, and 2.9 MM bdp of water.

The artificial lift systems are distributed as follows: 9,648 Sucker Rod Pumps (SRP), 1,615 Progressing Cavity Pumps (PCP) and 1,336 Electric Submersible Pumps (ESP). There are some important experiences with gas lift, plunger lift and hydraulic jet pump, but are not considered in this study. Close than 90% of the pumps are installed between 3,000 ft to 8,000 ft depth, producing flow rates over 1,500 bpd of fluid

More than 3.1 MMbpd of water are injected in 2,400 wells in water flooding projects, therefore 41% of the oil is produced from this method. Due to the mature state of the basin, every year, new waterflooding projects are implemented for increasing and to hold the oil production of the basin. With every new project, not only increases the gross production per well, but also increases the depth of the new reservoirs.

The combination of these factors resulted in a higher power to be transmitted from the prime mover to the pump, coupled with the increasing down hole temperature.

Another factor, is the restriction provided by the most common casing diameter (5 ½ "), limiting the outside diameter of the pumps, the tubings and sucker rod sizes, and the shaft diameter too in some systems.

In order to overcome these conditions, not only requires new technology in materials and design, but criteria for operation on the surface to achieve it.

This paper presents a theoretical and practical analysis of the mechanical and operational limit of the most used artificial lift systems in Golfo San Jorge Basin such as the PCP, ESP and SRP.

The analysis not only considers the technical aspects of each critical component and new technologies, but also is supported by reservoir information, operational conditions from 11,000 wells and software simulations for each system.

One of the main objectives of this paper is to provide a guide for selecting and designing artificial lift Systems as SRP, PCP and ESP in similar oilfields and conditions.
Adjustments in Teaching Petroleum Engineering Field Operations Lab—An LSU Experience
Authors: Radonjic Mileva , Bourgoyne Darryl , Panchadhara Sneha
Published: October 2009

Educating and preparing engineers for the 21st Century requires adequate changes in the style we teach and demonstrate knowledge, concepts and their application under complex conditions. Energy industry is undergoing fundamental changes globally, which needs to be transferred into the classroom, in order to enable future engineers to be prepared for contemporary issues in all aspects of oil and gas industry, especially exploration and production. One of the areas to be addressed at the LSU Petroleum Engineering is how we teach laboratory classes in order to prepare our students to easily adopt new safety requirements implemented in industry. In addition to technical competency required for high safety standards, it is also critical to develop a certain kind of behavior that will ensure acts of responsible, ethical decision making and leadership in the work place.

Application

Engineering graduates need to be ready to adjust to the workplace not only in terms of technical competency but also more increasingly in their behavior and attitude towards safety, environmental issues and diverse social surrounding during their careers. The field operations laboratory presented an ideal setting to experiment with teaching, demonstrating and grading styles, which resulted in a positive outcome. The changes were in the following areas: An increased number of hands on exercises on safety components that were practiced on the common safety devices donated by Ruelco.com.Undergraduate students were involved in demonstration, creating an open teaching environment.Experimentation with laboratory report writing using a scientific style of laboratory diary which was handwritten.Visits to the industry were incorporated, both, training and a production facility.Finally, written and practical performance was graded.
Investigation of Stress-Dependent Fracture Permeability in Naturally Fractured Reservoirs Using a Fully Coupled Poroelastic Displacement Discontinuity Model
Authors: Tao Q. , Ehlig-Economides C. A. , Ghassemi A.
Published: October 2009

Fractures are the main channels of production/injection in naturally fractured reservoirs; therefore the fracture permeability is a key parameter to production optimization and reservoir management. Pressure depletion in naturally fractured reservoirs can result in effective stress change that, in turn, can change fracture permeability. We apply a fully coupled poroelastic displacement discontinuity method to model the fracture permeability change during production in naturally fractured reservoirs. The fully coupled poroelastic displacement discontinuity method employs a boundary element displacement discontinuity model for the behavior of rock discontinuities and fractures under changes in stress from pore pressure variations due to fluid flow in both the matrix and fractures. The nonlinear Barton-Bandis joint mechanical medel is applied to represent the fracture deformation including normal and shear deformation. Sensitivity studies using the numerical model show that fracture permeability decreases with pressure depletion during production in fractured reservoirs under isotropic stress conditions. However, in critical stress conditions the fracture permeability may increase with pressure depletion during production because of the fracture dilation caused by fracture slide, which may explain near well permeability improvement observed in shale gas reservoirs. Simulations of pressure transient behavior show that behavior characteristic of stress dependent fracture permeability can be identified in conventional pressure buildup data, and over a longer time frame the model can be used for production data analysis. Matching with field data enables quantification of external stress contrast and fracture stiffness, and the result can provide a more rigorous forecast of production decline and primary oil or gas recovery efficiency for wells in naturally fractured reservoirs.
Real-Time Long Distance Teaching: An Overview of Two Years of Tele-Teaching Between Texas and Germany
Authors: Teodoriu Catalin , Reinicke Kurt M. , Falcone Gioia
Published: October 2009

This paper presents the experience gained while using a very simple and efficient tele-teaching technique based on available systems integrated in Windows packages. In contrast to expensive, time-intensive systems that use high-end technologies, our system incorporates ordinary webcams on laptop computers, Microsoft NetMeeting online conferencing software, and remote control of a distant computer.

We show the advantages of these simple resources and the student response to the teaching process for a highly sophisticated petroleum engineering class delivered to students in Clausthal-Zellerfeld, Germany from offices in College Station, Texas. The experience over two years of tele-teaching using easily available standard internet messengers and MS Windows-integrated meeting packages has resulted in enthusiastic student acceptance and preference for our low-cost system over more expensive, complex approaches to distance learning. We include our recommendations for building a system that works efficiently yet minimizes the costs.
A Systematic Study of Alkaline-Surfactant-Gas Injection as an EOR Technique
Authors: Srivastava Mayank , Zhang Jieyuan , Nguyen Quoc P , Pope Gary A.
Published: October 2009

Alkaline-Surfactant-Polymer (ASP) flooding is an attractive enhanced oil recovery method. However, some reservoir conditions are not favorable for the use of polymers or their use would not be economically attractive due to low permeability or other unfavorable conditions. Foam can be an alternative to polymer for improving the displacement efficiency in chemical-EOR process. The use of foam as a mobility control agent by co-injection or alternate injection of gas and chemical slug is termed, here, as Alkaline-Surfactant-Gas (ASG) Process. Foam reduces the relative permeability of the injected chemical slug that forms microemulsion at ultra-low oil-water interfacial tension (IFT) and generates sufficient viscous pressure gradient to drive the foamed chemical slug. The concept of ASG process as an enhanced oil recovery technique is relatively new, with very little experimental and theoretical work available on the subject. Polymer is replaced by foam in corefloods experiments as a mobility control agent. Phase behavior and ASG coreflood experiments were carried out to identify high performance chemicals, designed for both foaming and strong IFT reduction performance. The coreflood experiments were performed on sandstone and dolomite rock samples. Oil recovery and coreflood pressure response were evaluated to determine the success of the process. Different injection strategies for foam generation were investigated, and mechanisms of mobility control by foam were studied. Several promising surfactants, with dual properties of foaming and emulsification, were identified and used in the coreflood experiments. Maximum recovery of 95% of remaining oil after waterflood was observed. Oil recovery and pressure responses from ASG experiments are comparable to ASP coreflood experiments carried out under similar conditions. Experimental data show a strong synergic effect of foam and ultra-low oil-water IFT on oil recovery. Compared to polymer, foam has lower cost associated with its use and is less susceptible to biological, shear, and thermal degradation. The use of foam in chemical EOR can reduce the technical disadvantages associated with polymer in low permeability and fractured reservoirs.
A Theoretical Study of Acid Fracture Conductivity Under Closure Stress
Authors: Deng J. , Hill A. D. , Zhu D.
Published: October 2009

The conductivity of acid-etched fractures depends on spaces along the fracture created by uneven etching of the fracture walls remaining open after fracture closure. In this study, we have modeled the deformation of the irregular fracture surfaces created by acid etching and the resulting fracture conductivity as closure stress is applied to the fracture.

In our previous work, we modeled the dissolution of the fracture surfaces in a formation having small-scale heterogeneities in both permeability and mineralogy. This model yielded the geometry of the etched fracture at zero closure stress. Beginning with this profile of fracture width, we have modeled the deformation of the fracture surfaces as closure stress is applied to the fracture. At any cross-section along the fracture, we approximate the fracture shape as being a series of elliptical openings. Assuming elastic behavior of the rock, we calculate how many elliptical gaps remain open and their sizes as a function of the applied stress. The sections of the fracture that are closed are assigned a conductivity because of small-scale roughness features using a correlation obtained from laboratory measurements of acid fracture conductivity as a function of closure stress. The overall conductivity of the fracture is then obtained by numerically modeling the flow through this heterogeneous system.

Our previous work shows that high fracture conductivity can be created in acid fracturing if heterogeneity of the rock leads to the formation of channels along the fracture surfaces. In this study, we have determined how the channels in acid fracturing remain open as closure stress is applied. This model predicts the rock characteristics that are necessary for acid fracture conductivity to be sustainable under high closure stress.
The Variability of Gamma Ray Tool Response and Calibration as a Function of Tool Design
Authors: Pederson Raulie , Haecker Bill , Minette Daniel
Published: October 2009

In the last 5-10 years there has been a significant proliferation in the companies providing MWD gamma logging tools. A given MWD logging company might have 6 or more different gamma detector designs in their logging fleet. Historically, we know that different designs have produced different responses that need to be characterized. Calibration, dark current, detector sensitivity can all be affected by design.

In this paper, this question will be addressed through extensive API test pit logging, lab data, and Monte Carlo modeling. The foundation of the work is the running of five different detector designs from several different manufactures in the API gamma ray test pits. These tools are run in the API pits as bare sondes, and with a 4″ collar. They are also calibrated with two different types of gamma calibrators.

This work is extended with lab work with additional detectors. The laboratory procedure is directly tied to the API test pits through the use of tools and calibrators used at the API pit. Measurements are then made with different detector designs, as well as a number of different detectors of the same design.

Finally, the experimental work is complemented by Monte Carlo modeling. The Monte Carlo is benchmarked against the experimental results and then used to extend the range of investigation.

From this work, we are able to determine the variability of the following as a function of detector design: Dark Current (the count rate in a clean formation)Calibrator API ValuesCollar Shielding EffectsAbsolute API Pit ValuesEnvironmental Effects

In addition, we will be able to determine the variability of the dark current and the collar shielding effect between different detectors of the same design.

Finally, the effects on this on well logs will be addressed. First the effects of the uncorrected variation on the measured API values and the impact this has on formation evaluation will be discussed. Then means of minimizing these effects, and the resultant impact on formation evaluation will be presented.
Unified Model of Drainage and Imbibition in 3D Fractionally Wet Porous Media
Authors: Motealleh Siyavash , Ashouripashaki Mandana , DiCarlo David , Bryant Steven L.
Published: October 2009

We develop a grain based model for capillarity controlled displacement within 3D fractionally wet porous media. The model is based on a novel local calculation of the position of stable interfaces in contact with multiple grains. Each grain can have a different, arbitrary contact angle with the interface. The interface is assumed to be locally spherical for menisci separating the bulk non-wetting and wetting phases. The fluid/fluid interfaces between pairs of grains (surfaces of pendular rings) are assumed toroidal. Because the calculation of interface position is entirely local and grain-based, it provides a single, generalized, geometric basis for computing pore-filling events during drainage as well as imbibition. This generality is essential for modeling displacements in fractionally wet media. Pore filling occurs when an interface becomes unstable in a pore throat (analogous to Haines condition for drainage in a uniformly wet throat), when two or more interfaces come into contact and merge to form a single interface (analogous to the Melrose condition for imbibition in uniformly wet medium), or when a meniscus in a throat touches a nearby grain (a new stability criterion). The analytical solution for stable interface locations generalizes the Melrose and Haines criteria previously validated for pore-level imbibition and drainage events in uniformly wet media.

The concept of tracking the fluid/fluid interface on each grain means that a traditional pore network is not used in the model. The calculation of phase saturation or other quantities that are conveniently computed in a network can be done with any approach for defining pore bodies and throats (e.g. Delaunay tessellation, Voronoi tessellation, and medial axis methods). The fluid/fluid interfaces are mapped from the grain-based model to the network as needed. In addition, the model is robust as there is no difference in the model between drainage and imbibition, as all criteria are accounted for both increasing and decreasing capillary pressure.

To validate the model, we perform a series of drainage/imbibition experiments (oil/water) on fractionally wetted porous media prepared by mixing oil-wet grains with water-wet grains. In both experimental and simulation results, the drainage/imbibition curves shifts to lower capillary pressure with increasing fraction of oil-wet grains.

Using the model, we delineate which pore filling criteria occur as a function of initial wetting phase and wettability of grains. The shape and position of the pressure-saturation curve is shown to be a function of the pore filling types, and hysteresis arises naturally from the model.
Application of pH-Triggered Polymers for Deep Conformance Control in Fractured Reservoirs
Authors: Lalehrokh Farshad , Bryant Steven L.
Published: October 2009

Water injection is commonly employed to increase the average reservoir pressure and displace the oil. However, water flooding is not always successful. The most important problem is channeling of the injected water into high permeability zones which occur in heterogeneous reservoirs. This is particularly true in naturally fractured reservoirs.

Injecting low viscosity pH-triggered polymers into the reservoir to block the already swept fractures and high permeability zones is a promising solution. No injection of high viscosity gels or triggering agents is needed is this process. Polyacrylic acid microgels can swell a thousand fold as the pH of the surrounding solution changes, with an accompanying large increase in viscosity. In this paper we studied the factors affecting the feasibility and the placement of pH-triggered polymers into fractured reservoirs by performing several coreflood experiments in fractured cores.

Polymer treatment reduced the overall core permeability in all cases in contact with different minerals in various sandstone and carbonate fractured cores. At polymer concentrations of 1% or greater, the permeability reduction was more than a factor of ten. The polymer microgels showed excellent consistency after being one month in reservoir condition at 58°C and resisted flow at pressure gradients up to 80 psi/ft. The selection of polymer and salt concentration in polymer solution depends on the application and desired PRF value. However, the 1% polymer concentration and 3% NaCl concentration is recommended due to the ease of polymer preparation, injectivity, reasonable geochemical buffering time and PRF values.
Predicting Depth of Penetration of Downhole Perforators
Authors: Gladkikh M. , Harvey W. B. , Halleck P. M.
Published: October 2009

Productivity of a cased-and-perforated well depends on completion parameters (charge, shot density and phasing), formation properties (lithology, anisotropy, permeability, fluid properties and saturations), and environmental conditions (pressure and temperature). A shaped charge produces a jet of dense, typically solid material traveling at very high velocity which penetrates casing, cement, and formation. This penetration process creates a tunnel in the rock connecting the reservoir and the wellbore. Stress waves generated during penetration damage the rock around the tunnel, creating a complex zone of mechanically deformed rock material. Explosive and metallic debris may mix with damaged rock material. Depending on the specific conditions (mechanical rock properties, permeability, fluid viscosities, interfacial tensions, pressures and fluid storage volumes), reverse surge flow following the jet penetration partially or completely clears the tunnel of the charge and rock debris. The resulting tunnel is a rugose, tapered cylinder roughly characterized by its diameter and total depth of penetration. The degree of cleanup and total depth of penetration are two of the most critical parameters influencing flow performance of a perforated well.

This work focuses on predicting penetration depth and providing a summary of recent progress and advances in this area. A review of industry penetration prediction methods is presented, including relationships based on surface perforation tests in concrete targets, as well as correlations of penetration depth with properties that could be measured by downhole logging tools. Despite a variety of available methods and published experimental data, penetration depth results are often inconsistent with each other and of questionable use in predicting actual downhole penetration. Moreover, most studies have concentrated on the influence of a single penetration variable. There have been no systematic studies of the interaction of parameters on perforation penetration.

This paper emphasizes the critical need for such a study, given the difficulty of downhole measurements of penetration depth to finally achieve reliable penetration predictions, and suggests future directions and conditions necessary for such a study.
Production Optimization Benefits through Application of Standardized Operating Procedures for Reservoir Monitoring
Authors: Bhushan Vikas , Lee Robert , Mukerji Parijat
Published: October 2009

The ultimate goal of excellence in brownfield management is to increase the value of a field through maximizing production and ultimate recovery within its remaining economic life. The ability to successfully apply reservoir management techniques is essential in meeting the challenges of optimizing late life production. Further, the standardization of operating procedures yields benefits both in terms of optimizing the use of technical resources and in successfully meeting well intervention objectives. It also facilitates and promotes an active collaboration between the operator and service provider, both during logging operations and later when the log data is evaluated and interpreted.

We will demonstrate the benefits that the successful development and implementation of robust Standard Operating Procedures (SOP's) for cased hole reservoir monitoring can have. These will be illustrated with recent examples from the Brent Field in the UK North Sea. Developing these SOP's was not a simple process, and required a detailed understanding of the rock & fluid properties, reservoir production mechanisms and contact movements, topsides constraints, and reservoir behavior coupled with experience in data acquisition & interpretation methods which are tailored to meet the specific challenges of the field.

The SOPs have been applied to meet a range of specific challenges such as the identification and perforation of gas zones, differentiating reservoir fluid type (e.g. formation/injection water and oil) to access bypassed oil, contact monitoring, and identifying impairment to increase production rates. Success in the development and application of SOPs requires service company involvement and cooperation in all aspects: program design, data acquisition (including real time support and monitoring to ensure data quality), processing, presentation and interpretation. Examples will be provided of how this involvement has contributed to the successful outcome of interventions in the Brent field.

The development of robust SOPs for reservoir monitoring yields benefits in terms of defining and streamlining data acquisition and interpretation methodologies, tailored to suit the specific field characteristics and challenges. Further, it facilitates knowledge transfer to staff unfamiliar with the tools & techniques captured within the SOPs and enables a more efficient interaction between operating company and service provider.
Monobore Completion System Provides Low-Cost Completion Option
Authors: Ingvardsen Don , Kritzler Jim
Published: October 2009

Many of the wells completed today could be classified as short life or harvest wells. Some of these would not be economically feasible using high end completion components, and methods. Monobore wells can be a solution to this dilemma.

This paper will discuss several methods in which monobore well design can save considerable time while lowering the overall completion cost. Several methods will be discussed, and case histories provided to substantiate the results and savings. Methods will include the following:

Disposable completions using minimal completion components. Cemented monobores using cement-tolerant components, and methods/procedures of completing wells. Staged cementing completion designs for openhole monobores. Two-trip monobore systems Detailed case histories of the methods above, discussing the advantages and disadvantages of each method. Results of pilot program with live gas lift valves in place during cement operations instead of dummy valves.

Illustrations along with detailed procedures will be discussed to better understand how each completion method can address the numerous opportunities, and problems associated in well completion design. Case histories will be provided to validate each method.
Development of a Comprehensive Rheological Property Database for EOR Polymers
Authors: Lee Seungjun , Kim Do Hoon , Huh Chun , Pope Gary A.
Published: October 2009

One of the most important factors in chemical enhanced oil recovery (EOR) is mobility control, for which partially hydrolyzed polyacrylamide (HPAM) and other polymers are extensively used. An accurate description of the polymer viscosity is needed to simulate field performance accurately. Rheological properties of the EOR polymer solutions depend on the polymer's molecular properties and concentration, salinity, shear rate and temperature.. Rheological measurements with commonly employed EOR polymers were made and the parameters in the rheological models that correlate polymer viscosity with these variables were determined and used to develop a polymer database.

The rheological measurements have been made to characterize the apparent viscosity of EOR polymers (mainly HPAM polymers) as a function of shear rate, polymer concentration, polymer molecular weight, degree of hydrolysis, salinity, hardness, and temperature. In addition to the steady shear viscosities, the oscillatory rheological properties have also been measured to better define the polymer behavior during flow in reservoir rocks. In view of the recent EOR applications to recover viscous oils and to offshore fields, the data were obtained for wider ranges of the polymer molecular weight and concentration, and salinity, than those reported in the literature. A comprehensive compilation of the rheological data and polymer parameters for currently available EOR polymers was needed since these polymers often have different properties than similar polymers that were studied during the earlier period of active chemical EOR research 20 to 30 years ago.
Using Cross-Polarized Microscopy to Optimize Wax-Treatment Methods
Authors: Bacon Mark M. , Romero-Zerón Laura B. , Chong Ken K.
Published: October 2009

Paraffin wax deposits are known to be a worldwide problem in the upstream petroleum industry. Considerable resources are expended on inhibiting or removing wax deposits every year. Paraffin wax is not the only type of crude oil based wax. Microcrystalline waxes, composed of naphthene and iso-paraffin molecules, also exist but are not well studied. The predominance of paraffin (also called macrocrystalline) wax and paraffin wax inhibition techniques will likely lead to paraffin wax treatments being applied to naphthene based reservoirs. It is unclear how well a paraffin based treatment will apply to naphthene based oil.

The current study investigates the use of Cross-Polarized Microscopy (CPM) to determine if a crude oil contains macrocrystalline or microcrystalline waxes. CPM can determine the size and morphology of wax crystals because crude oil wax crystals are known to be anisotropic. Macrocrystalline waxes are known to present with larger, elongated structures while microcrystalline waxes present with smaller, rounded structures. The type of wax present in the crude oil can be determined using crystal morphology and size. Knowing which type of wax is present in the oil will help to choose which type of wax inhibitor will be used. This study has shown that CPM can be an effective tool to determine the type of wax present in a crude oil. Paraffin wax crystals are shown as being elongated structures with statistically larger sizes than the microcrystals. Microcrystalline waxes are shown to be statistically smaller and rounded structures. CPM is a simple, cost-effective method that can be used in addition to standard tests to determine if a crude oil is paraffin or naphthene based. In the future this test can be used to prevent paraffin wax treatments being applied to naphthene based reservoirs and to help optimize the specific inhibitor chosen.
Complex Flow and Composition Path in CO2 Injection Schemes from Density Effects in 2 and 3D
Authors: Nasrabadi Hadi , Firoozabadi Abbas , Ahmed Tausif
Published: October 2009

CO2 injection has been used to improve oil recovery for the past three decades. In recent years, the improved recovery method has become more attractive because of the dual effect; injection in the subsurface allows: 1) reduction of CO2 concentration in the atmosphere to reduce global warming, and 2) improved oil recovery.

Some of the projects considered for CO2 injection are based on CO2 miscibility with oil at the minimum miscibility pressure (MMP). The MMP is often measured in a slim tube. The slim tube data are used for the purpose of field evaluation and for the tuning of the equations of state. The slim tube represents one-D horizontal flow.

In this work, we will show that CO2 MMP, often measured in a slim tube, may not have relevance to CO2 injection in a 2D (or 3D) reservoir. When CO2 dissolves in the oil, the density often increases. The increase in density changes the flow path form one-D to two-D (downward flow). On the other hand, when a gas phase evolves from mixing of CO2 and the oil, the gas phase is often lighter than CO2 and the oil. In downdeep injection for the some of the cases when CO2 is heavier than the oil (in the conditions of some offshore high pressure field) the evolved gas phase moves upward due to buoyancy. As a result of these two density effects the compositional path in a reservoir is radically different from the flow path in a slim tube. The change in flow path may prevent miscibility development. The flow path is also altered from heterogeneity and from diffusion.

In this work, we present results from simulation in slim tube and in a two-D vertical reservoir and show significant effect of gravity and heterogeneity. One main conclusion from this work is that for successful CO2 injection projects there is need to have accurate density data for CO2/oil mixture with different CO2 compositions.