bluuebunny/crossref_metadata_2025_split huggingface dataset:
3D RSS for 24" Section Sets Inclination Record on the Grane Field by Introduction of an Integrated Drilling and Surveying Bottomhole Assembly
Authors: Saeverhagen Erland , Erichsen Cato , Nesheim Anders , Waldron Glen 
Published: September 2008

Abstract
To maintain production and reservoir pressure on the Grane field, production, gas and water injection wells today are placed in the outer reaches of the reservoir. Due to the shallow reservoir depth, immediate and high deviation is required in the 24" section, to enable sufficient lateral displacement. Due to short intermediate slot distance, it is also imperative to obtain precise directional measurements to control anti-collision.
The 24" build up section was planned with a continuous DLS of 2.8°/30m starting approx. 150m below seabed, where the well still was vertical, through soft and unconsolidated sand and shale formations, until reaching the required sail angle at 80° inclination, followed by an 860m tangent section to section TD.
Past experience from the Grane field, have shown problems in achieving the required build rate using a conventional PDM-mud motor with high offset tilt angle. Wireline gyro also was the standard solution to obtain directional control in the tight "kick off " area just below the platform, which was very time consuming with survey sensors placed far behind the bit.
The new BHA was designed to achieve all directional objectives, consisting of a 24" 3D RSS system and a combination of Gyro MWD and Magnetic MWD tools integrated in the BHA, thus removing the need for PDM motor and wireline Gyro surveys.
This paper will describe the technology used and the achievements from well 25/11 G-31, where the planned well path was drilled according to plan.
Diffusion Coefficient of n-alkanes in Heavy Oil
Authors: Guerrero-Aconcha U. , Salama D. , Kantzas A. 
Published: September 2008

Abstract
The use of hydrocarbon solvents in the recovery of heavy oil has been increased because of the advantages they have over the thermal methods under some reservoir conditions. The injection of a miscible solvent in the reservoir implies a mass transfer process which is governed by a diffusion coefficient. Consequently the measurement of the diffusion coefficient is extremely important. This, however, presents a significant amount of challenges in the laboratory and in the data analysis, mainly because of the viscous and opaque nature of the heavy oil and the dependence on concentration of the diffusion coefficient. The Matano-Boltzmann method has been used in the past to obtain the concentration dependency of the diffusion coefficient of solvents in heavy oil. Although the method successfully shows that such dependency exists, the results exhibit abnormal trends.
In this work the concentration profiles of three n-alkanes in heavy oil were obtained in the laboratory using Computed Assisted Tomography (CAT), and the "Slopes and Intercepts" analytical technique was used to calculate the concentration-dependent diffusion coefficients. The results are in good agreement with the theory of diffusion in binary mixtures. In addition a comparison is presented with the Matano-Boltzmann method. Finally the Vignes model was successfully used to also perform predictions on the studied systems.
Improved Prediction of Oil Recovery from Waterflooded Fractured Reservoirs
Authors: Salimi Hamidreza , Bruining Johannes 
Published: September 2008

Abstract
Simulations of waterflooding in fractured media are based on the Warren and Root (WR) approach, which uses an empirical transfer function between the fracture and matrix block. Arbogast used homogenization to formulate an improved flow model in fractured media, leading to an integro-differential equation; also called the boundary condition (BC) approach. A wellposed numerical 3D model for the BC approach has been formulated. This paper derives this numerical model to solve full 3D integro-differential equations. The results of this model are compared with the ECLIPSE results. For the interpretation it is useful to define three dimensionless parameters, which characterize the oil production in fractured media. The most important of these parameters is a Peclet number defined as the ratio between the time required to imbibe water into the matrix block and the travel-time of water in the fracture system. The results of the WR approach and the BC approach are in good agreement when the travel-time is longer than the imbibition time. However, for times with the same order of magnitude and for the travel time shorter than the imbibition time, the approaches give different results. The BC approach allows the use of transfer functions based on fundamental principles, e.g., the use of a rate dependent capillary pressure function. When implemented, it can be used to improve recovery predictions for waterflooded fractured reservoirs.
Waterflood Surveillance in the Mars Field Deepwater GOM: Mississippi Canyon Block 807
Authors: Weiland Jeff , Mikulencak Duane , Fox Phil , Suparman Suparman , Frisch Gary , Azari Mehdi 
Published: September 2008

Abstract
Waterfloods serve many purposes and their performance can have major economic impact on the drilling, production and management of hydrocarbon reservoirs. The primary purpose of the Mars (Mississippi Canyon 807) waterflood in the deepwater of the GOM is to increase recovery efficiency in three main reservoirs. In addition, the waterflood helps maintain reservoir pressure in selected sands, which minimizes compaction and subsequent well failure.
Surveillance of the waterflood through carbon/oxygen logging, of the formation through compaction logging, and of the individual reservoir layers through multi-rate production logging is critical to the success of the Mars field. The program has consisted of obtaining time-lapse logging and reservoir pressures combined with reservoir modeling. Data has been obtained in the injection, producing, and monitor intervals of several Mars wells and proven to be vital to the evaluation of waterflood efficiency and the prediction of the waterflood front.
A monitoring logging program has been conducted in the Mars area since 1996, with initial baseline surveys, to the present day monitoring surveillance program. The logging program has had two purposes. The primary purpose of the program has been to monitor the "sea water" waterflood saturation fronts with carbon/oxygen logging and integrate this data into the reservoir models. A second purpose has been to monitor strain as a result of reservoir compaction and to monitor the effects of the waterflood on the rate of strain. This data is used to help determine wellbore integrity and ultimately to predict wellbore failure. It also provides calibration data for the compaction model used in reservoir simulation.
Selected Mars well examples are described in detail to highlight the results of time-lapse monitoring of the waterflooded reservoirs. A comparison of log data with simulation modeling predictions demonstrates the benefit of the data acquisition and evaluation methods. Discussion is focused on best practices learned during the 12 year program, how log responses have helped verify modeling parameters, and on justification of future activities.
Implementing i-field Initiatives in a Deepwater Green Field, Offshore Nigeria
Authors: Adeyemi O.S. (Tope) , Shryock S.G. (Steve) , Sankaran Sathish , Hostad O. , Gontijo J. 
Published: September 2008

Abstract
In recent times, i-field, e-field, digital oilfield of the future etc. have dominated discussions focusing on increasing the recovery from both shallow and deep water assets using electronic technologies. The common theme is the ability to integrate tested and emerging information and communication technologies (ICT) with asset management workflows for improved recovery, collaborative decision making and prompt intervention thereby increasing the asset's bottom-line.
A methodology adopted for implementation of i-field in one of Chevron's mega projects is presented in this paper. The Agbami field, located in deepwater offshore Nigeria is a subsea development incorporating crestal gas and peripheral water injection. It is located in ~ 5000 ft of water and consists of a 38 well development program to be implemented in 3 phases. The first phase involves 22 wells – 12 producers, 6 water and 4 gas injectors. The well completion incorporates intelligent well completion (IWC) – downhole flowmeters, pressure & temperature gauges and interval control valves (ICVs). These downhole accessories will be controlled using electric and hydraulic controls/instrumentation with Subsurface, Subsea and Topsides data acquired and transmitted to a central data historian on the FPSO in relevant time.
The implementation of a robust architecture for Data and Information Management System involving acquisition, processing, storage and replication (from offshore to onshore) is conceived to be the bedrock of the other main focus areas namely: Production Optimization, Reservoir Management & Surveillance, Facilities & Equipment Reliability, and Asset Decision Environment. The impacts of these four focus areas and the methodology engaged in identification, prioritization and generation of the relevant workflows have been discussed.
The expected gains from implementing i-field include improved well and facilities uptime resulting in increased efficiency and reliability, increased production, improved ultimate recovery, and better overall performance from automation of several routine activities. This will ultimately increase the expected value (EV) of the asset through better and prompt decision making using appropriate collaborative tools. In addition, best practices and lessons learned for development and deployment of i-field initiatives in a green field environment are presented with possible applications to mature brown fields.
A Simplified Method for Prediction of ECD Increase with Drillpipe Rotation
Authors: Hemphill Terry , Ravi Krishna , Bern Peter , Rojas Juan Carlos 
Published: September 2008

Abstract
The ability to accurately predict the effect of drillpipe rotation on Equivalent Circulating Density (ECD) remains a challenge for those involved in engineering today's complex wells. In many of these challenging wells (extended-reach drilling, deepwater, HPHT, etc.), the safe drilling window between hole collapse and fracturing is often narrow. Accurate prediction of the effect of drillpipe rotational speed could allow better optimization of operational parameters in the drilling process, and hopefully reduce the incidence of violation of the safe drilling window.
Recently ECD results measured at different circulation rates and drillpipe rotational speeds were modeled and presented to the industry. The calculation methods involved several complex factors including estimated drillpipe eccentricity, nonlinear shear rate modeling coefficients, drillpipe geometry correction factors, etc. The presented results constituted the best-available correlation with direct downhole pressure measurements, but still showed improvement was needed.
Further development work has been done in this same area to reduce the complexity of the calculations and yet improve modeling accuracy. It was noticed that the effect of increasing drillpipe rotational speed at a constant annular velocity produced a near-linear increase in ECD. In addition the ratio of the internal diameter of the hole or casing and the outer diameter of the drillpipe (Di/Do) was found to be a meaningful modeling parameter that could transcend explicit values of estimated drillpipe eccentricity. Data from the earlier work and some additional field results were then reworked using the new calculation scheme, which is presented in the paper. The results presented in this paper show that this calculation technique can produce better prediction of field measurements of downhole pressure changes while rotating and is much simpler to use. Not only can it help in navigating through the safe drilling window, but it also can be used to separate pure rotation effects from other coupled wellbore events, such as hole cleaning and barite sag.
Using Nanoparticle Technology to Control Formation Fines Migration
Authors: Huang Tianping (Tim) , Crews James B. , Willingham John R. 
Published: September 2008

Abstract
Various methods have been employed mitigate fines migration problems that result in decreased productivity in oil and gas wells. This paper discusses the use of nanotechnology to fixate the migrating fines using the interaction between the migrateable fine particles present within the formation and nanoparticles associated with a proppant pack treatment. This paper will introduce the use of unique nanoparticles (nanocrystals) for treating hydraulic fracture proppant packs to fixate formation fines.
Nanoparticle technology allows the combining of the extremely high surface area available using these particles, approximately 200 m2 /g, with the surface action of the material to fixate migrateable formation fines. Acting within the proppant bed, this fixation of the fines leads to more stable hydrocarbon inflow by reducing the rapid production decline often resulting from fines migration towards the wellbore. The nanoparticles can be added on-the-fly to hydraulic fracturing fluids to treat proppant just prior to being pumped downhole. The treated proppant pack will then capture and retain migrating fines, thereby preventing them from invading the pack and migrating towards the wellbore where flow impairment could occur.
Laboratory developmental testing is presented to demonstrate the effectiveness of using this unique application of nanoparticle technology and field trials of this application should be completed by September, 2008.
The Future of Fracturing-Fluid Technology and Rates of Hydrocarbon Recovery
Authors: Crews James B. , Huang Tianping , Wood W. Russell 
Published: September 2008

Abstract
A high percentage of oil and gas wells worldwide are hydraulically fractured in order to allow a reservoir to become economically producible and to improve the rate of hydrocarbon production. Annual global investments for hydraulic fracturing are at one billion dollars. Crosslinked polymer fluids are the most commonly used fracturing fluid because of cost and performance criteria. The crosslinked polymer fluids exhibit exceptional performance features to initiate and propagate a fracture, carry proppant and control fluid leak-off into the reservoir during a treatment. However, crosslinked polymer fluids leave a significant amount of polymeric filtercake material in the fracture once a treatment is completed. Decades of improving oxidative, enzyme and other breakers for the polymer fluids has only marginally improved from about 30% to about 50% by weight the amount of polymer residue left within the fracture. The result has been a continuation of much lower than optimum hydrocarbon recovery rates for many wells.
New surfactant-based fluid technology is being developed that will in many geographic regions replace polymeric-based fracturing fluids over the next decade. This paper will introduce a new fluid technology that uses nanoparticles, special internal breakers and low molecular weight viscoelastic surfactants (VES) to achieve the performance features of crosslinked polymer fluids but leaves little to no gel residue. Unique nanoparticles have been found that "pseudo-crosslink" VES micelles together through electrostatic and van der Waals forces. This micelle-networked fluid property will allow unique "pseudo-filtercake" to form on porous media, like crosslinked polymer fluids exhibit, to control fluid leak-off and improve fluid efficiency. The special internal breakers reside within the micelles and go wherever the fluid goes, including the networked micelles composing the pseudo-filtercake. The internal breakers controllably break the viscosity of the VES-based pseudo-filtercake by rearranging the VES micelles to spherical non-viscous structures and dispersed nanoparticles that readily flow back with producing fluids and do not impair the proppant pack conductivity. The primary result will allow a wide range of hydraulically fractured reservoirs to produce at substantially higher sustained rates than presently achievable, particularly for deepwater and other high investment wells.
Completion System Allows for Interventionless Stimulation Treatments in Horizontal Wells with Multiple Shale Pay Zones
Authors: Vargus Greg , Howell Matt , Hinkie Ron , Williford James , Bozeman Tim 
Published: September 2008

Abstract
This paper will discuss case studies and details of a pinpoint stimulation/completion process that uses stimulation sleeve technologies in conjunction with swelling packers as part of an openhole, horizontal, well lateral liner that is anchored by an expandable liner hanger. This system will allow an operator to accurately place several individual stimulation treatments without additional intervention in the wellbore. This is accomplished by installing the closed stimulation sleeves and swellable packers as part of the completion string, (horizontal openhole liner) and positioning the string in the wellbore so that the stimulation sleeves are located within the desired production pay zones. The completion string is then anchored in position with an expandable liner hanger. The swellable packers are allowed to expand for a few days and isolate the zones between each of the sliding sleeves. Stimulation/frac equipment is rigged up, and a series of progressively larger balls are dropped throughout the multistage pumping operation. The balls land on the tapered baffles in the sleeves, each of them opening in sequence and sealing off the previously treated zones below. Once opened, a stimulation sleeve allows pumping a treatment into the zone where it is positioned. After being opened, the stimulation sleeves maintain the capability to be closed and reopened, with minor intervention, with a shifting tool allowing for restimulation or other workover at a later date.
This new service is a field-proven process with 120 wells completed and more than 850 stages/zones treated. This method reduces the time and cost needed to complete multiple intervals in a well, and bring production on line faster by comparison to conventional multizone horizontal fracturing/stimulation techniques such as multiple perforating and setting plugs.
Volatile Phosphorus Free Gellants for Hydrocarbon Based Fracturing Systems
Authors: Lawrence S. C. , Kalenchuk A. C. , Ranicar K. , Dhillon S. , Baig A. 
Published: September 2008

Abstract
In recent years, a number of refineries in Western Canada and the United States have discovered the formation of scale or sludge in their distillation towers. The build up of large amounts of sludge lowers the efficiency of refineries to the point where it must be removed. The process of sludge removal requires that the refinery shut down at a cost of millions of dollars in lost production to the refinery operators. Analysis of the sludge has revealed that it has an extraordinarily high phosphorus content (8 to 12%). Further investigation into the origin of the phosphorus in the sludge raised concerns that chemicals used in hydrocarbon fracturing fluids, specifically volatile phosphorus containing hydrocarbon gellants, are responsible for the refinery fouling. This paper will discuss how the origin of the volatile phosphorus in the hydrocarbon gellants has been determined and how a viable, ultra low volatile phosphorus solution for hydrocarbon gelling has been developed.
Fluid Sampling in Carbonates-Challenges and Best Practices
Authors: Dawoud Ahmed , Zaggas John , Haddad Sammy 
Published: September 2008

Abstract
A heterogeneous carbonate reservoir can be partly evaluated using OH logs but not fully. Even if production testing is used for evaluation, important details can often be overlooked such as individual pressure behavior of thin laminated sections and/or existence of different fluids within the reservoir section itself.
Zonal pressure testing and sampling done with dynamic formation testers will more than often fill in the missing gaps and in fact will contribute into optimizing future testing and production for the field under investigation. This is usually achieved by an initial comprehensive pressure evaluation profiling (to obtain reservoir pressures and mobilities) followed immediately (in most cases same run) with a comprehensive formation fluid sampling program, by the end of which a comprehensive picture of individual streaks of interest, in terms of pressures and fluids, has been formed.
The employment of Dynamic Formation Testers has nowadays become something of a norm, but the challenges faced in harsh environments can sometimes be daunting. These challenges include operations in extremely tight and overbalanced environments, high solid mud systems, distinction and sampling of formation water in WBM environments or oil in OBM systems, high percentages of H2S formations, long pumping times and stations, collecting representative (single phase) fluid samples and of course environments of high pressures and temperatures.
The present paper will discuss the various problems faced with dynamic formation testers in a typical everyday wireline run, in a typical carbonate environment (U.A.E) and discuss a variety of topics that include formation heterogeneity, supercharging, tool options, real-time (RT) monitoring while logging, invasion, thick transition zones and vertical interference tests. Examples and where applicable recommendations to working around these problems are also presented.
Dual-Role of Water-Soluble Metallic Additives on Modifying In-situ Combustion Performance Using Large Activation Energy Asymptotics
Authors: Akkutlu I. Y. , Yortsos Y. C. 
Published: September 2008

Abstract
Unlike other thermal recovery methods, air injection and in-situ combustion produces significant amounts of heat in the reservoir. However, the process is subject to acute external heat loss rates due to high temperature gradients in place. Consequently, reservoir temperatures may be reduced considerably, leading to a deteriorated combustion performance and debilitated field operations. Goal of this paper is to determine under which reservoir conditions the combustion temperatures could be maintained at sufficient levels. Previous investigators have partially addressed this issue using kinetic and combustion tube experiments. In the absence of heat losses, it has been repeatedly shown that water-soluble metallic additives improve the self-sustainability limit of combustion front in oil and sand mixtures. In general, this has been attributed to dual-role of the additives on the combustion performance: (1) kinetics of heterogeneous oxidation reactions inside the combustion front are modified, namely the catalytic effect; (2) specific surface area of the porous medium ahead of the combustion front is increased, namely the fuel deposition effect. It is currently a common belief that appropriate introduction of such materials in a reservoir environment could enhance the performance of combustion process and, hence, improve the recoveries. Determining their role on in-situ combustion performance requires that the mechanisms of combustion are well understood. Complex physical and chemical nature of the problem at the pore-scale has prevented detailed investigations using physical and numerical models, however. Here, we approach the problem analytically using a sequential reaction (HTO/LTO) combustion front propagation model, based on the large activation energy asymptotics, and introducing systematically the reaction kinetics and fuel deposition effects of the additives to the model. Coherent propagation of the reaction regions are then investigated in terms of their temperatures, propagation velocity and the oxygen consumption efficiency. It is found that an improved combustion performance can be observed only if both the kinetics and fuel deposition effects develop under the reservoir conditions.