bluuebunny/crossref_metadata_2025 huggingface dataset:
Pore-Scale Simulation of Dispersion in Porous Media
Authors: Garmeh G. , Johns R. T. , Lake L. W.
Published: December 2007

Mixing of miscible gas with oil in a reservoir decreases the effective strength of the gas, which can adversely affect miscibility and recovery efficiency. The level of true mixing that occurs in a reservoir, however, is widely debated and often ignored in reservoir simulation where very large grid blocks are used. Large grid blocks create artificially large mixing that can cause errors in predicted oil recovery.

This paper examines the mixing that occurs in porous media by solving for single-phase flow in a connected network of pores. This work differs from network models in that we directly solve the Navier-Stokes equation and the convection- diffusion equation to determine the velocities and concentrations at any location within the pores. Flow in series and layered heterogeneous porous media are modeled by using many grains in different arrangements. We consider both slug, continuous, and partial injection as well as echo tests (single-well tracer tests) and transmission tests (interwell tracer tests). We match the concentrations from the pore-scale simulations to the analytical convection dispersion solution that includes both transverse and longitudinal dispersion coefficients.

The results show that for flow in series and in layers, echo and transmission longitudinal dispersivities become equal and reach an asymptotic value if complete mixing over a cross section perpendicular to flow has occurred. In practice, the asymptotic value of dispersivity may never be reached depending on pattern-scale heterogeneity and well spacing. Transverse dispersion coefficients also are scale dependent, but they decrease with traveled distance. We further demonstrate that the classical Perkins-Johnston relationship between longitudinal dispersion coefficient and fluid velocity is obtained. We conclude that echo dispersivities are reliable indicators of true mixing in porous media.
Technology for Confecting Polymer Solution With Desalted Produced Water
Authors: Liu Shumeng , Dong Xigui , Ban Hui , Wang Tao , Pan Wenlong , Yu Haijun , Guo Cuiling , Suo Chunlei
Published: December 2007

Polymer flooding technology has been widely used in Daqing oilfield of China in recent years. To maintain the viscosity of polymer solution, fresh water was used to confect polymer solution instead of produced water. Then, a problem was generated that the produced water could not be injected into the stratum totally. The superfluous produced water must be treated to meet the requirement of discharge, which increased the cost of production. In this paper, we try to desalt the produced water using electrodialysis principle. A set of experimental equipments that could generate desalted produced water 300 m3/d, was operated at a produced water treatment station of Daqing Oilfield. The experimental results indicated that the total salinity of desalted produced water less than 1000 mg/L. Comparing with fresh water, the polymer solution confected with desalted produced water has a sound character, its viscosity increases 63.5%, and the recovery ratio increases 4.5 percentage points. This experimental study has an important significance for the balance of oily water of production and injection in Daqing Oilfield. This produced water desalination technology would have a better application prospect in polymer flooding production.
Advanced Technology for Rapid Minimum Miscibility Pressure Determination (Part 1)
Authors: Adyani Wan Razak Wan Nurul , Kechut Nor Idah
Published: December 2007

A prototype apparatus integrating a state-of-the-art micro-slim tube (MST) was developed and tested for rapid determination of Minimum Miscibility Pressure (MMP). The equipment, GEMA (Gas Extraction & Miscibility Analyser), uses an advanced technology of data acquisition and control system, making it a reliable tool for rapid MMP determination. MST is an unpacked, coiled stainless steel column of 30 m long and 0.32 mm ID. The small bore capillary column permits a high linear displacement rate resulting in a much shorter time needed per test of only 2 to 3 hours (including cleaning) as compared to 2-3 days if the conventional slim tube apparatus is used. The relatively small height-equivalent-to-a-theoretical-plate (HETP) in a capillary column ensures thousands of multiple contacts between the injected gas and oil, which cannot be practically achieved in the conventional slim tube. With this newly upgraded equipment, MMP determination for one sample takes only 2-3 days to complete as opposed to 2-3 weeks with the normal slim tube.

The method has been tested for various Malaysian reservoir fluid samples and the MMP results obtained are consistent with values estimated using published correlations such as Johnson & Pollin (1981), Glaso (1985) and Cronquist (1978). The equipment is proven to be very reliable to determine the MMP.
An Investigation of Near-Wellbore Flow Properties Using Sonic Scanner Measurements and Interval Pressure Transient Testing
Authors: Ayan Cosan , Petricola Mario , Knight Philip , Lalanne Bruno
Published: December 2007

Wireline Formation Tester (WFT) pretest success ratio (good versus tight pressure points) has been traditionally low in East Kalimantan-Indonesia over decades despite technological advances. One possible reason has been postulated as alteration of near-wellbore formation properties during drilling operations. The relatively tight gas sands are drilled with significant overbalance due to a mix of depleted and virgin zone layers using oil based mud systems. To further investigate possible near formation alteration, an extensive evaluation program was undertaken, using new generation sonic logs, WFT-multi-probe interval pressure transient testing (IPTT) and coring.

A Sonic Scanner* survey was conducted in Tunu field to investigate possible nearby formation alteration, followed by MDT*-multi-probe IPTT. The Sonic Scanner dipole radial profiling showed some radial property change at several zones. The altered zone radial extent was quantified. The MDT-IPTT tests quantified the, virgin zone effective gas permeability and permeability anisotropy as well as gave a fair idea of the open hole skin factor. Combination of the results gave altered zone radius, altered zone permeability, virgin zone permeability and anisotropy on a comparative basis between different zones. Moreover, the results from both dipole radial profiling and MDT-IPTT indicated that formation alteration not necessarily increases with overbalance. The results quantified nearby formation alteration, showed this as a possibility and can further help in selecting the best perforation strategy.
Gas Coning Control for Smart Wells
Authors: Leemhuis A. P. , Belfroid S. P. C , Alberts G. J. N.
Published: December 2007

A strong increase in gas influx due to gas coning and the resulting bean-back because of Gas to Oil Ratio (GOR) constraints can severely limit oil production and reservoir drive energy. The purpose of this paper is to demonstrate that oil production after a gas breakthrough can be optimized by means of an inflow control strategy that takes the effects of ‘natural gas lift’ and production choking into account. Within the research framework of the "Integrated System Approach Petroleum Production" (ISAPP) knowledge center of TNO, TU Delft and Shell, it has been shown that this optimization can be achieved by controlling the location and amount of gas influx in a horizontal smart well.

In order to show a proof of principle we have implemented a PID feedback controller, which controls the gas fraction in a well by changing its Inflow Control Valve (ICV) settings, on a test case in a dynamic reservoir simulator. We introduce a three step strategy for production optimization: firstly we model how the controlled production rate after breakthrough depends on the gas fraction; secondly we will determine the optimal gas fraction; thirdly we will consider the capability of a PID controller to produce at this optimal gas fraction.

Simulation experiments show that a PID controller is an effective means to prevent a full gas breakthrough and, moreover, can be used to increase the produced oil rate by tuning ICV settings to an optimal gas fraction. These experiments also demonstrate the benefits of using downhole ICV control in comparison to wellhead control.

In current operations ICVs are mostly used to completely shut down well segments that experience gas coning. We show that by keeping these ICVs open in a controlled way the, otherwise undesirable, phenomenon of gas coning can be used to optimize oil production.
Inverted Venturi: Optimising Recovery Through Flow Measurement
Authors: Ong J. Tim , Aymond Michael , Albarado Tesia , Majid Javid , Daniels Paula , Jordy Dustin , Lafleur Louis
Published: December 2007

The advent of high crude oil prices and mature fields has seen a rush for efficient recovery methods. This has spurred the development of "monitor-feedback-control" systems through intelligent well system (IWS) and interventional processes. Traditionally, downhole permanent flow measurement is performed using differential pressure meters; e.g. venturi. The intrusive nature of these flowmeters prevents easy access for interventional processes and creates a loss in well lift.

The main aim of an inverted venturi design is to allow full bore access whilst maintaining the downhole measurement accuracy requirements. The flowmeter has a reverse mechanical design compared to a restrictive venturi. Instead of a constricted section in the tubing, the inverted venturi has an expanded section. The theoretical principles are still based around simple energy and momentum conservation. Due to these facts, the operation of the tool requires the use of a pair of high resolution pressure gauge. The main breakthrough came from the development of a high resolution pressure transducer.

Surface testing of the flowmeter has demonstrated flow measurement uncertainty better than 8% for instantaneous flow rate measurement and better than 1.5% in bulk flow rate measurement. These flowmeters have also been deployed successfully in the field. Installation of these flowmeters in the Gulf of Mexico (GOM) region has shown a similar level of accuracies and has provided immense value to production. Apart from providing full bore access, the flowmeter is more robust as it is able to withstand higher gas volume presence in production rather than that of restrictive venturi. Due to the sensitivity of the pressure transducer, the flowmeter is also able to detect the presence of gas in production which adds value to the recovery process.

Installations are planned in the near future in IWS applications. These will include applications for multi-zone allocation flowmeters, injection flowmeters for both gas and water applications and commingled flow production meters. The application for the inverted venturi is limitless as it is not constrained by the typically issues surrounding restrictive venturi such as the loss of wellbore access and well lift.
Uniquely Characteristics Mixed-Metal Oxide (MMO) Fluid Cure Lost Circulation While Meeting European Environmental Regulations
Authors: Oswald Reinhard , Marinescu Pavel , Vlasceanu Paulin
Published: December 2007

Even though "New Technology" has become the catch phrase in today's drilling industry, downhole losses still account for an important part of well costs overruns worldwide. Losses not only increase the mud bill but also to a significant extent affect the total project cost and results, through rig downtime, multiple cementing operations or other alternative solutions attempts. The risk of the operations that encounter total loss of circulation is also increased, which require alternative costly solutions. In addition, the continuous demand for improved drilling performance, safety and environmental compliance and highly targeted production rates magnify the challenges.

This paper addresses the application of uniquely engineered fluid and the results of a drilling campaign in traditionally total lost circulation problematic fields by a major operator in Romania. The system used is the latest generation of Mixed-Metal Oxide (MMO) products, a water-based fluid system with outstanding solids suspension properties, but very high shear-thinning, that still screens easily even at high flow rates and through fine screens. It contains no components that can harm the environment, so the waste generated could be categorized as EWC (European Waste Code) 01 05 04  according to the European waste regulations.

In this campaign, the system was used in several wells where previously total loss circulation, multiple cement plugs, and lengthy drilling breaks were common. The authors detail the successful implementation and continuous improvement of the system in nine wells where it eliminated or dramatically reduced losses so valuable rig time was saved while eliminating multiple trips and time consuming cementing attempts. During the campaign, increased inhibition was deemed advantageous to drill through shale formations in the same interval with thief zones, so newest research and development products were introduced. Extensive laboratory and field tests results are also included, together with field results.
Reservoir Characterization and Modelling of Stacked Fluvial/Shallow Marine Reservoirs: What is Important for Fluid-Flow Performance and Effective Reservoir Prediction?
Authors: Samantray Ajay , Kraaijveld Martin , Hognestad Jon , Bulushi Waleed
Published: December 2007

Earth modelling and field implementation experience in fluvial/shallow marine clastic reservoirs suggests that relatively large, km to m scale geologic features such as stratal framework and facies architecture dominate the model behaviour and influence the accuracy of performance forecast more than numerically driven pore scale heterogeneity.

Twenty seven reservoir models were built by using different modelling methods and varying a combination of more uncertain reservoir characterization parameters ranging in scale from field to voxel to pore level. The models were largely influenced by deterministic geological controls rather than numerically driven stochastic variations. Guided by regional work, core and image log integration, the large scale stratal framework, the facies scheme and the zonal variograms were kept the same in all the models while the rock fabric and pore scale heterogeneity were varied using facies models, reservoir trend maps, and permeability contrast scenarios. These 27 models were all subjected to history match constrained fluid-flow simulation with a partially active aquifer, and peripheral and pattern waterflooding. Static and dynamic parameter uncertainties were handled by using experimental design.

The results show that oil recovery from existing wells at 98% water cut ranges from 25 to 40% in these 27 models. Also, there are differences (greater than 20%) in water-breakthrough time, water cut, and cumulative water production. While the large scale stratal framework defined the flow units and provided fundamental control on zonal production behaviour (e.g. differential depletion, early water breakthrough, and conformance control), the differences in oil recoveries and water cut among all models were found to be related to variation in m- scale rock heterogeneity rather than pore scale heterogeneity and permeability contrast.

Do we need more complex, numerically exhaustive models to predict flow performance in channelised reservoirs with reasonable well control? Some of the simple, but geologically constrained models we constructed provided superior flow-simulation results, impacted development concepts and led to accurate prognosis from new drills.
Case History: Application of Coiled Tubing Tractor to Acid Stimulate Open Hole Extended Reach Power Water Injector Well
Authors: Al Shehri Ayedh M. , Al-Driweesh Saad M. , Al Omari Mazen , Al Sarakbi Samir
Published: December 2007

With the increasing complexity of well completion, the rigless intervention work is becoming more challenging. Conventional techniques are no more adequate to access long horizontal wells to perform intervention work such as acid stimulation, logging, and zonal isolation.

This paper will describe the process of using a downhole coiled tubing (CT) tractor to access a horizontal open hole (OH) extended reach power water injector (PWI) well in the Ghawar field, the world's largest oil field, to perform a huge matrix acid stimulation job. The volume of the treatment is considered one of the largest for a PWI and the first utilization of a CT tractor in the Ghawar field. The paper will review the process of candidate selection, job design and planning, execution, and results and post job evaluation. The job set an excellent example of advancement in intervention technique accessing long horizontal wells beyond the normal reach of coiled tubing. In this job, the CT tractor has increased the reach of CT by 54% and a world record of coiled tubing tractored interval in horizontal OH of more than 5,000 ft was achieved. The injection rate of the stimulated wells was increased by more than twofold.
New Method for Supercharging Estimation
Authors: Wu Jianghui , Meister Matthias , Li Baoyan
Published: December 2007

Formation testers are used to measure formation pressures at discrete depths to determine pressure gradients for zones of interest. The gradients are used to identify fluid types, to estimate the level of pressure depletion, and to check connectivity between different zones. Pressure supercharging is often observed during formation testing while drilling or wireline formation testing, especially when the permeability of the formation is low. The pressure measurement is greatly affected by supercharging, and accurate initial formation pressure can not be obtained directly.

In order for the supercharged pressures to be used for reservoir management purposes, the amount of supercharging has to be estimated and subtracted from the measured pressures. We present a single-phase invasion model which couples a mudcake growth model with an analytical formation fluid-flow model. Supercharging is a function of mudcake quality, pressure overbalance, and properties of fluid and formation. In a while-drilling operation, the time exposed to the overbalance is also a factor. Inversion is conducted to fit the invasion model with pressure measurements. The inverted five model parameters include initial formation pressure, compaction factor, mudcake permeability, mudcake thickness (at an arbitrary time before the testing), and skin (internal mudcake). The non-uniqueness of the inversion result is quantified with a statistical method that uses a Monte Carlo sampling method.

In addition to the statistical method, a deterministic method is developed to estimate initial formation pressure. This method assumes that flow resistance of mudcake grows at a constant rate during the test interval. Initial pressure and growth rate are calculated deterministically from at least three pressure measurements. Field cases are presented to demonstrate the robustness of both statistical and deterministic methods. The estimated initial formation pressure has good agreement with time-lapse LWD pressure measurements.

In this paper, a more accurate analytical formation fluid- flow model was used instead of line-source approximation. The internal mudcake is represented by the skin factor in the analytical model. The coupled invasion model has five parameters. While the previous seven-parameter model requires two sets of pressure measurement under two different hydrostatic pressures, the new model can be applied without the practical limits, it needs only one set of pressure measurements.
High-Angle Well Deliverability Modeling for Openhole Gravel-Pack Completion Under Ultrahigh Gas Rate
Authors: Tang Yula , (Bill) Huang W. S.
Published: December 2007

Open-hole Gravel packing is increasingly becoming a standard practice in the deep-water, subsea completion environment. A Chevron offshore gas reservoir will be developed with highangle near-horizontal wells with openhole gravel packs completion (OHGP) for its first phase development. The ultra high rate for individual well could be up to 320 MMSCFD and the non-Darcy effect is too significant to overlook. The objective of this investigation is to build an accurate model, to validate and quantify the non-Darcy, mechanical skins for the high-angle OHGP gas wells, and finally to develop a recommendation for the optimized design.

A comprehensive semi-analytical model was developed based on modification of the horizontal well model. The additional pressure drop is added to consider the mechanical skin and non-Darcy flow in the near-wellbore zones of drilling damage, mud-cake, gravel packs, and the sand screen.

This investigation indicates that the non-Darcy effect could significantly affect the production rate and the economics of the project. It was found that 80° wells have a 35% average reduction in PI due to skin and non-Darcy effect. The PI for 60° wells reduces by 62% comparing to the 80° wells due to concentrated flow to a much shorter wellbore and much larger scaled skin and non-Darcy term. Uncertainty analysis was performed on non-Darcy beta-factor, formation damage parameters, and gas effective permeability.

Wellbore open-to-flow area and hydraulics affect the high rate gas well's performance significantly. The preferred design is an OHGP slanted well at 80 degrees without shunt tube (6.366" ID), which can yield much higher PI than the base design. The sound engineering design of the well completion would allow us to deliver superior value through this huge gas property.
Using Production Logs to Calibrate Horizontal Wells in Reservoir Simulation
Authors: Wang Y. , Moreno J. , Harfoushian J. H.
Published: December 2007

Horizontal wells often present a substantial challenge in reservoir simulation. In a recent field review, we experienced difficulties modeling long horizontal wells due to the combined complexity of the wells and the reservoir. This reservoir is located in an offshore field that produces oil from a relatively thin oil rim. The reservoir also contains a large gas cap that provides the dominant energy for reservoir recovery. The reservoir is composed of interbedded, shallow marine-ridge sands with some coarsening-up sequences.

A typical horizontal well in this field has perforation intervals of about 1,200–2,900 ft, penetrating depositional sequences from the bottom up, and produces from multiple formations. Wells are placed close to the oil-water contact, sufficiently far from the gas-oil contact to reduce the effects of gas coning and channeling.

Due to the large heterogeneity of reservoir properties in different layers, complexity of the geological feature, and the dynamics within the horizontal wellbore, it is very challenging to reproduce the actual production profile in the simulation model. For example, an unfavorable combination of a sump (variation in depth) in the well trajectory and fluid holdups may prevent the toe from producing. The dynamics are difficult to capture without direct production logging and the use of special options of the simulator.

In this study, appropriate technologies were applied to solve this problem. Production logging was implemented on four wells. The results revealed that some perforation intervals do not contribute to production. It also exposed allocation problems in the historical production data. This information was used to validate the performance of some wells and to calibrate other wells that exhibit different production profiles. Some simulator options such as multi-segment wells and PLT reporting have been applied to facilitate this calibration process. With this calibration, history matching becomes a more guided process, and the resulting model is more consistent with the actual performance, thus, enhancing its predictive power.

This paper describes certain special wellbore dynamic behaviors that have not been covered in the literature. It illustrates the challenges of simulating horizontal wells and how production logging is used to resolve the problem and calibrate the model for better predictive power.
Irong Barat Field Development: An Integrated Approach to Maximize Asset Value
Authors: Ghapor Zamri Abdul , Kuang Lim Hock
Published: December 2007

The Irong Barat field, located offshore Peninsular Malaysia, has been producing since 1984 from the Irong Barat A (IBA) platform. Production in the field, which is complexly faulted with major and minor faults dividing the field into four major fault-block compartments, is primarily from the Group H channelized facies reservoirs. The increased complexity in structural interpretation and reservoir mapping as a result of the complex faulting posed a challenge in managing risks and uncertainties in developing and maximizing value of this field.

Upon successful initial development of the primary fault block, additional data was acquired to mature further opportunities resulting in additional field development at Irong Barat, particularly the IBA Redevelopment, and the Irong Barat B and Irong Barat C developments. Integration of reservoir surveillance/studies, geological and geophysical analysis, facilities and drilling technologies was applied by Irong Barat Teams to mitigate the risks and uncertainties of the identified development opportunities. As a result of this effort, over the last six years crude production has increased from ten to 25 thousand barrels of oil per day and developable reserves have grown by about 50 million barrels.

This paper describes the integration of key technologies and approach taken to manage the risks and uncertainties in these projects to increase the Irong Barat field value.
Successful Hybrid Slickwater Fracture Design Evolution—An East Texas Cotton Valley Taylor Case History
Authors: Handren Patrick , Palisch Terry
Published: December 2007

As the development of tight/unconventional and partially depleted gas reservoirs has increased, so has the demand for more innovative hydraulic fracture designs. Operators are increasingly placing proppant with slickwater, linear gel or hybrid fracture designs. While the benefits of these designs are typically attributed to a reduction in gel damage of the proppant pack, many operators mistakenly believe that the resulting fractures are not conductivity-limited.

Since few (if any) models on the market can adequately model the propagation of a slickwater frac as well as the associated proppant transport and deposition, it becomes difficult to optimize these fracture designs. This has led many operators to incorrectly assume that only small diameter sand or resin-coated sand may be placed in these types of designs, and that these products supply ample flow capacity.

However, one East Texas operator has combined insight into proppant transport with an appropriate understanding of realistic proppant pack conductivity to develop a novel, hybrid slickwater fracture design. This design has allowed the placement of larger diameter, higher conductivity proppant in fractures that many believed could not be placed either operationally or economically. Additionally, this operator has developed a unique pumping strategy to place the highest conductivity proppant in portions of the fracture where it provides the most value.

This paper will present a case history of these new hybrid slickwater fracture designs in this operator's East Texas, Cotton Valley – Taylor completions. The design theory and sequential improvements will be documented, including larger diameter, higher strength proppants, as well as a novel placement design. Field results from the first six wells fractured will be presented, showing substantial increases in gas production compared to similar offset completions. Economics will also be shown to illustrate the tremendous value added to completions utilizing this hybrid fracture design.
Computational Fluid Dynamics (CFD) Erosion Study for Chokes
Authors: Peri S. , Rogers B.
Published: December 2007

Because erosion is a common cause of failure in oilfield equipment, it is beneficial to approach the issue at the product design level. The areas most susceptible to erosion occur near changes in flow direction because here the particles are most likely to deviate from the flow stream and impinge on the surface geometry. While both experimentation and computer simulation are used to study erosion, experimental testing often proves difficult to perform for specific conditions. Computational fluid dynamics (CFD) simulations are used to predict erosion rates, with flow modeling and particle tracking being key tools for predicting erosion.

This paper presents a set of curves to estimate erosion of different components of the choke as a function of choke position and flow rate using CFD. Erosion results are plotted in terms of thickness loss per time in units of mils/yr as provided for each component for varying flow rates and sand volume concentrations. Results from the study show that the erosion rates increase in a quadratic fashion with respect to the flow rate. The predicted erosion rates for various scenarios are examined and compared to experimental results.
Optimizing the Production System Using Real-Time Measurements: A Piece of the Digital Oilfield Puzzle
Authors: Thompson Robert B. , Shanmugam Valli , Sinha Shekhar , Collins Natalie , Bodwadkar Suhas , Pearcy Marc , Herl Stan
Published: December 2007

The oil industry is investing millions of dollars in the infrastructure of digital oilfields in an effort to increase efficiency and recovery. An important part of the puzzle, transferring data from the wellsite to the office in real-time, is very much solved. However, this data is largely used to monitor the status of wells and equipment, and in most cases, the life cycle of the data ends there. A key part of the puzzle is to utilize the real-time data to optimize the production system, from the wellbore to the reservoir where most of the value lies. With the current infrastructure and technology we can get real-time data up to every second. The challenge is to extract the right information from that data at the right time to impact the way fields are managed.

This paper discusses the workflows utilized in identifying production optimization and enhancement opportunities from large amounts of streaming data flowing from a number of wells. Case studies are presented for mature waterfloods in four different fields with over 60 wells. The economic impact of surveillance is quantified through electrical costs, efficiency in fluid movement, and enhanced reservoir deliverability. The real-time data analysis for the entire field revealed opportunities to increase the production in the short-term, as well as the necessity to adjust the long-term exploitation strategy.

The methods and examples in this paper show the value of applying digital oilfield technologies in one of the most cost sensitive environments in our industry. Observations based on a large number of wells during a 2-year period show that over 50% of the wells can benefit from some form of optimization, resulting in a substantial increase in production.
The Effect of Weighting Material Sag on Drilling Operation Efficiency
Authors: Omland T. H. , Saasen A. , Zwaag C. V. D. , Amundsen P. A.
Published: December 2007

Drilling in subsurface formations requires control of down-hole pressures. Weighting materials are typically added to the drilling fluid and provide, ideally, a homogeneous fluid column with an even density to control these pressures. However, experience has shown that keeping the weighting material in suspension can be challenging. Especially when drilling with synthetic or oil-based drilling fluids the nature of the fluids prevents the generation of sufficient gel structures to keep high density particles in suspension. On one offshore operation the rig had to be evacuated. Because barite was sagging out of the drilling fluid and left a residual fluid phase with too low density, gas was entering the well during drilling.

This paper provides a review of the sag studies performed to date, describes various testing techniques for sag evaluation as well as giving description several field cases where weighting material sag occurred. It also shows how the efficiency of operations was affected. The cases are analyzed and suggestions are made concerning the operational elements that may have provoked the incidents. The analyses use time-based drilling data to provide detailed information of the operational sequences prior to the sag incidents and how the incident was handled at the site.

Several previous studies have shown no correlation between weighting material sag and standard measurements of drilling fluid properties. The present study, however, focuses on other fluid properties essential to hinder weighting material sag.
Contacting More of the Barnett Shale through an Integration of Real-Time Microseismic Monitoring, Petrophysics and Hydraulic Fracture Design
Authors: Daniels J. , Waters G. , LeCalvez J. , Lassek J. , Bentley D.
Published: December 2007

Horizontal wells represent a growing percentage of the rig count in unconventional gas wells in the United States. With effective stimulation techniques they have been shown to have favorable economics compared to vertical wells in the same reservoir. This is because of the large hydraulic fracture surface area that can be created from horizontal wells if effective stimulation techniques are employed. The Barnett Shale formation is the reservoir that has seen the largest growth using this technique in recent years.

Estimated to extend over 54,000 square miles, the Barnett Shale formation displays different reservoir characteristics and properties in its different regions. The heterogeneous nature of this unconventional play makes standardization of the completion process problematic. One technology that has been used with increasing regularity to understand complex fracture geometry is microseismic (MS) fracture mapping1. Recent technology advances have made it possible for an onsite computer to process the thousands of seismic traces and deliver MS events hypocentral locations in a matter of seconds to a viewer in the fracturing treatment vehicle. Microseismic mapping used in conjunction with wellbore images and sonic logs has shed considerable light on the challenges faced in this reservoir.

Massive water fracs are currently used to create complex hydraulic fracture networks. This stimulation technique, while successful, often leaves behind unstimulated sections of the reservoir. In order to achieve optimum horizontal well stimulation the lateral section must be characterized so that geologically different intervals can be identified and the proper stimulation technique employed. Technology has progressed to the point that microseismic monitoring of hydraulic fracture stimulation can efficiently provide extensive diagnostic information on fracture development and geometry in real-time.

The case studies in this paper show how the use of real-time fracture mapping allows for on-the-fly changes in fracture design. Mapping also impacts the perforation strategy and restimulation designs to maximize the Effective Stimulation Volume (ESV). ESV is defined as the reservoir volume that has been effectively contacted by the stimulation treatment as determined by microseismic event locations and density. This paper further correlates MS activity to log data and illustrates how logs can be used to estimate fracture geometry. This data is then used to design a fit-for-purpose stimulation that has the greatest chance of maximizing the ESV and production.
Improving the Value of Real-Time Drilling Data to Aid Collaboration, Drilling Optimization, and Decision Making
Authors: McLaren G. , Hayes M. J. S. , Brown N. M. , Okafor Z. , Megat I.
Published: December 2007

Evolution in the manner in which real-time data is provided by service companies in the drilling industry has led to real-time data being available via the Internet from most wells drilled worldwide. The platform for viewing this real-time data is usually through a variety of viewers embedded in Web server software. By using technologies to enable the clear presentation of this Web-based data in real time to the end user—including data visualization, model comparison, and rig time usage—it is possible to improve real-time collaboration and perform drilling optimization actions from both a location remote to the wellsite (e.g., the operator's office or even a service company office) and the wellsite itself. By looking at three case studies in two locations (the North Sea and the Gulf of Mexico), it is possible to show how technologies that enable collaboration between onshore and offshore personnel and manage drilling risks not only improve operations monitoring and reporting but reduce drilling process time.

The three case studies demonstrate aid which eliminated an intermediate liner string; improved real-time understanding of well conditions by managing hole cleaning and drilling risks, ensured that a casing string could be successfully landed on bottom; and enabled cause-and-effect analysis of drilling events in real time in addition to post event analysis for improved evaluation of the drilling process. In all these cases, the use of enabling technologies within one integrated application brings advantages to the drilling process through the clear presentation of real-time drilling data, which allows easier interpretation of real-time drilling measurements.
Pressure-Wave Propagation Technique for Blockage Detection in Subsea Flowlines
Authors: Chen Xianghui , Tsang Ying , Zhang Hong-Quan , Chen Tom X.
Published: December 2007

Solids blockage due to wax deposition and/or hydrate formation in subsea flowlines is one of the major risks for deepwater production systems. Blockage causes high pressure drop and even stop of oil and gas production. The ability to determine the location, length and severity of blockages allows operators to select cost-effective mitigation or remediation strategies and execute the corresponding mitigation or remediation procedures efficiently Due to the difficulty to access subsea flowlines, a remote technique to detect the blockages is highly desirable. This study investigated the feasibility of using the pressure-wave propagation technique to detect blockage in subsea flowlines.

Pressure waves are generated when the production stream is released for a very short period of time at the flowline outlet on the host facility (either a fixed platform or a floating platform). The pressure waves propagate through the flowlines at the local sonic speed and are reflected to the flowline outlet after encountering a blockage. The time and amplitude of the reflected pressure wave from the blockage are quantitatively related to the characteristics of the blockage. This transient method was examined numerically and experimentally in the present study. Results indicate that pressure-wave propagation technique is a remote, non-intrusive and cost efficient method that can be applied to detect blockages in gas transport pipelines and subsea wet gas multiphase flowlines with gas as the continuous phase.
Beyond Money, What Is Important to Petroleum Professionals?
Authors: Collarini Cheryl R. , Sibille Amanda B.
Published: December 2007

A recent survey of petroleum industry professionals, including many engineers, was conducted by Collarini Energy Staffing Inc. to determine what non-monetary factors are most important to them. The respondents were asked to accept that they are fairly compensated, then asked to rank 36 factors in three categories: the position, the company environment, and the impact of the position and company on the employee's personal life. The respondents also were requested to rank those factors in two ways: how important each issue is to them and how well their current company meets their needs related to that issue. Over 10,000 professionals were asked to participate. The identities of the respondents were not recorded in order to provide complete anonymity. The response was significant. Beyond compensation, and in a highly competitive market for excellent people, other factors become important. The results of the survey were consistent across gender and occupation, with only minor fluctuations. Challenging work and corporate reputation were ranked of primary importance. Ranked second, but numerically very close, were all factors that relate to the people and the culture of the organization.
Theory and Application of Probabilistic Method of Designing Customized Interval Control Valves Choke Trim for Multizone Intelligent Well Systems
Authors: Ajayi Arashi , Konopczynski Michael
Published: December 2007

This paper describes a stochastic approach to the design of interval control valve choke trims for an intelligent well system. The paper builds on the deterministic approach of specifying the Cv characteristics of a multi-position control valve. The probabilistic method considers reservoir uncertainties in productivity indices, zonal pressure drawdown, expected production (or injection) rates and field production operation philosophy.

This design approach allows the control valve to meet the expected control objectives and ensures that the design trim is applicable to a wide range of well performance. The probabilistic method is demonstrated using real data from field examples.

The probabilistic design methods described in this paper are applicable to all intelligent well systems using variable choking valves, on both production wells and injection wells. The methodology is also applicable to intelligent well systems targeting reservoirs with characteristics that are widely uncertain. This method will enable the engineers to design an interval control valve (ICV) that incorporates reservoir uncertainties with field control philosophy leading to an optimized well delivery system.
On the Influence of Viscosity Upon ESP Performance
Authors: Amaral Gilmar , Estevam Valdir , Franca Fernando A.
Published: December 2007

This paper presents experimental data and a preliminary analysis on the operation of centrifugal pumps with viscous liquids. Two centrifugal pumps, a conventional radial (Ns = 1000) and a semi-axial electrical submersible pump - ESP (Ns= 3850) were instrumented and tested with water – 1 cP, and clear glycerin. The glycerin viscosity was varied from 67 cP to 1020 cP, through changes in temperature, encompassing the viscosity range of light to heavy oils. The main purpose of these tests, besides measuring the influence of viscosity upon the pump overall performance, was to supply detailed information on the energy transfer processes taking place in the pump internal components. To accomplish with that the pressure distribution along the flow path, through impellers and diffusers, from the pump inlet eye to the discharge section, was measured. Thus, besides measuring the flow rate, the total pressure difference, the speed, the power and the mean operation temperature, for a working liquid with various viscosities in a full range of operational conditions, the data showed the pressure evolution inside the pump. Later analyses revealed that there was a strong relationship between the flow hydrodynamics in successive pump devices in terms of head gain and viscous dissipation. This relationship was set by the pump operational operational conditions, flow rate and speed, and the fluid viscosity. In other words, how a diffuser performed depended on Reynolds number and the upstream flow through the impeller. Thus, any generalizing model dealing with the influence of fluid viscosity on the pump performance should account for these phenomena. For this reason, it is highly improbable that "black-box" approaches that neither consider the flow hydrodynamics of the successive connecting devices nor assess the influence of the Reynolds number on them could give proper viscosity correction factors for different pumps.
Examining Erosion Potential of Various Inflow Control Devices to Determine Duration of Performance
Authors: Visosky Jason M. , Clem Nicholas J. , Coronado Martin P. , Peterson Elmer R.
Published: December 2007

When producing long, horizontal zones, production rate is typically higher at the heel of the well than at the toe. The resulting imbalanced production profile may cause early water or gas breakthrough into the wellbore. Once coning occurs, well production may be severely decreased due to limited flow contribution from the toe. To eliminate this imbalance, inflow control devices (ICDs) are placed in each screen joint (sandstone formations) or debris barrier (carbonate formations) to balance the production influx profile across the entire lateral length and compensate for permeability variation. This creates equal production through each joint of screen to maximize recovery and rate.

Pressure drop is created through restriction or friction mechanisms. Restriction uses small holes or orifices to restrict flow. Friction utilizes surface friction of a long channel to create the required pressure drop. ICDs to effectively balance production inflow depend upon their ability to resist erosion. Because these ICDs are permanent downhole components, their long-term reliability is imperative.

Factors that determine erosion potential of ICD designs are fluid velocity, fluid particle concentration and design geometry. Calculations and computational fluid dynamics (CFD) modeling can be used to predict values for several factors independently, but not as a complete system. A full-scale erosion test is the most accurate way to demonstrate how the interaction of erosion factors affects the long-term reliability of downhole components.

This paper will detail the methodology behind ICD design, the use of CFD analysis in determining erosion potential, as well as the analysis of full-scale ICD erosion testing conducted at an independent testing laboratory.