bluuebunny/crossref_metadata_2025_split huggingface dataset:
The Evaluation of Enhanced (Carbonate/Sulfate) Scale-Dissolver Treatments for Near-Wellbore Stimulation in Subsea Production Wells, Gulf of Mexico
Authors: Jordan M. M. , Marlow D. , Johnson T. L. , Johnston C. 
Published: December 2007

Abstract
Dissolver technology has been developed and applied with varying degrees of success over the past few years to clean carbonate and the more challenging sulphate/sulphide scales from production tubing and process equipment. The intention of this proposed application was to select a chemical that could be applied into the near wellbore region of the reservoir to recover scale induced damage while not creating any secondary precipitation or negative wettability effects.
The impact of dissolver chemical formulation on the reservoir formation's wettability and the potential for mobilization of fines (both reservoir silicate and scale) has not been outlined before. In this paper reservoir condition coreflood studies are outlined where scale is formed within the cores to allow assessment of sulphate dissolver performance. This will form a critical part of the technical evaluation of the dissolver formulation suitability for field application. Results from these coreflood studies will be compared to those generated for the same chemicals in conventional static dissolver studies.
The practical concerns about deployment methods within subsea production wells are also emphasized. Specific reference will be made to the impact of metallurgy on chemical selection and the need to reduce corrosion risk within developments which utilize both carbon steel and super duplex requiring the development of higher pH non acid carbonate dissolvers.
This paper shows that simple dissolver tests can give misleading performance information as they only show dissolution rates, impact of concentration of active chemical or the increased dissolution possible with solvents. The use of pre scaled reservoir cores to assess the impact of dissolver performance and the potential for secondary formation damage allows the most effective dissolver with minimum formation damage potential to be selected for field application.
Rheology of Gas-to-Liquid Products, Alaska North Slope (ANS) Crude Oil and Its Blends for Transportation through the Trans-Alaska Pipeline System (TAPS)
Authors: Abhijeet I. A. , Chukwu G. A. , Khataniar S. , Patil S. L. , Dandekar A. Y. 
Published: December 2007

Abstract
It is projected that by the year 2015, Alaska North Slope (ANS) crude oil production will decline to such a level (200,000 to 400,000 bbl/day) that there will be a critical need for pumping additional liquids through the pipeline in order to maintain economic operation of the Trans Alaska Pipeline System (TAPS). The estimated proven and recoverable gas reserves of 38 trillion cubic feet (TCF) on the North Slope of Alaska can be converted to a high premium liquid product using the Gas-to-Liquids (GTL) technology. The GTL product can be transported from the ANS to the Southern port of Valdez, Alaska through the TAPS.
One of the proposed modes of transportation of the GTL products from ANS to market is by commingling it with crude oil as a single phase and pumping the mixture through the TAPS. This mode of transportation changes the properties of the GTL as well as the crude oil. The focus of this work therefore was to determine the physical and chemical properties of GTL and its blends with ANS crude oil, analyze the energy requirements for flowing the mixture through TAPS, and to determine the optimum blend ratio that would maximize the transportation economics. Four blends of GTL/crude oil mixture in the ratios of; 1:1; 1:2; 1:3; and 1:4; were prepared for their rheological evaluation and pressure drops at different temperature conditions.
The results of the analysis show that flow behavior of the GTL and GTL blends are temperature sensitive. Viscosity and density of the blends were found to decrease with increasing amount of GTL and increasing temperature. The optimum GTL/crude oil blend ratio of; 1:2.5 (28%: 72%) was determined to take full advantage of the economics of commingled flow of GTL/crude oil mixture through the TAPS.
Injectivity Impairment Due to Residual Oil Mobilisation (Treatment of Laboratory Data)
Authors: Vaz A. S. L. , Bedrikovetsky P. , Furtado C. , Siqueira A. G. , de Souza A. L. S. 
Published: December 2007

Abstract
Re-injection of produced water (PWRI) causes retention of solid and oily particles by porous rock causing decrease of permeability, cake formation and consequent injectivity decline. Maintenance of the injection rate results in increase of pressure gradient near to well.
Previous works consider effects of mobilization of residual oil in well vicinity due to increase of pressure gradient and, consequently, the increase of capillary number. The mobilized oil ganglia perform snap-off and release oil drops that move together with the injected particles; they are captured by porous rock causing additional formation damage.
A simplified analytical model that covers effects of oil drops generation and additional permeability reduction was also developed previously.
In the current work we tune the analytical model using laboratory data and discuss the occurring discrepancy.
Experimental Investigation and Network Modeling Simulation of Free Fall Gravity Drainage in Single-Matrix and Fractured-Blocks Models
Authors: Mollaei Alireza , Haghighi M. , Maini B. 
Published: December 2007

Abstract
Free Fall Gravity Drainage as an important recovery mechanism was investigated and analyzed experimentally and by numerical (network model) simulation for both single matrix and fractured blocks models. The results of free fall gravity drainage of these two models were compared to each other to determine whether or not the network of fractures intensify the free fall gravity drainage recovery of matrix blocks. For the experimental study, a set of glass micromodels with real pattern of porous media was constructed in two main forms of single matrix model (as a 2D simulator of conventional reservoirs) and fractured blocks model (as a 2D simulator of fractured reservoirs) in laboratory.
Also, two numerical network model simulators were programmed based on pore scale displacement mechanisms (drainage, imbibition and flow through films) to study and compare the behavior of free fall gravity drainage process in two models. The simulator takes into account the dominant displacement mechanisms observed in free fall gravity drainage glass micromodel experiments of both single matrix and fractured blocks models. Free fall gravity drainage experimental results of glass micromodel were used to validate the network model simulator. The mixed-wet wettability of glass micromodels was applied in network model simulator which allows oil to flow through wetting films in oil-wet regions and through spreading films on water in water-wet regions.
Method of Image-Analysis was used to generate pore and throat size distribution functions of glass micromodels. The simulators were used to study and interpret the effects of different parameters on free fall gravity drainage results. For this purpose, numerous sensitivity analysis scenarios were tested (run) by numerical simulators to evaluate the effect of different parameters (pore and throat size, fracture aperture, oil density, oil viscosity, gas -oil interfacial tension (sgo) and coordination number (Z)) on results of free fall gravity drainage process. Also, relative permeability and capillary pressure curves of both single matrix and fractured blocks models were generated by numerical network model simulator and are compared to each other.
Ranking of Geostatistical Reservoir Models and Uncertainty Assessment Using Real-Time Pressure Data
Authors: Yadav S. , Bryant S. L. , Srinivasan S. 
Published: December 2007

Abstract
This paper presents a novel approach to analyze the quasicontinuous pressure data for ranking high-resolution geostatistical reservoir models and uncertainty assessment. Real time monitoring of pressures through permanent downhole gauges is a recent development. A robust procedure to effectively use the enormous amount of data recorded by theses monitoring systems has been proposed and tested on a synthetic case.
Geostatistical simulations involve generating multiple equiprobable fine scale depictions of the reservoir heterogeneity each honoring the data available. The simulated pressure responses from these realizations could be quite different, yet the responses are not completely random. In spite of their differences, there are patterns, which occur in theses simulated responses. Such patterns can be identified by means of a mathematical tool called Principal Component Analysis.
The classical face recognition technique is then used to rank the geostatistical reservoir models. The simulated pressure data from the multiple realizations is analogous to "training set of faces" while the recorded or the historical data is the "face", which needs to be recognized form the training set. The method attempts to identify the geostatistical reservoir models, which show reasonable match in the dominating patterns in the simulated pressure data with the recorded pressure data. This approach mimics the "face recognition" or the "voice recognition" technique, which are already being successfully applied in their respective domains.
Efficiency of Miscible Displacement in Fractured Porous Media
Authors: Trivedi J. J. , Babadagli T. 
Published: December 2007

Abstract
During the injection of fluids that are miscible with oil for enhanced oil recovery, oil recovery and transport of the injectant are controlled by fracture and matrix properties in naturally fractured reservoirs (NFR). For such systems, the transfer between matrix and fracture due to diffusion is the main oil recovery mechanism. Similar processes can be encountered during the sequestration of greenhouse gases, and transport of contaminants in subsurface reservoirs. Understanding the effects of the parameters on the dynamics of the process is essential in modeling such processes. In fact, the description of matrix fracture interaction for dual-porosity dual-permeability models developed for NFRs is still a challenge.
Experiments were performed to study the process of diffusion during flow in fracture. 2-inch diameter and 6-inch length Berea sandstone and Indiana limestone samples were cut cylindrically. An artificial fracture spanning between injection and production ends was created and the sample was coated with heat shrinkable teflon tube. A miscible solvent (heptane) was injected from one end of the core at a constant rate. The effects of (a) oil type (mineral oil and kerosene), (b) injection rates, (c) orientation of the core, (d) matrix wettability (changed by aging the cores), (e) core type (a sandstone and a limestone), and (f) amount of water in matrix on the recovery performance were examined. The oil recovery for different matrix sizes, wettabilities, permeabilities, orientations, oil viscosities, and oil-heptane diffusion coefficients were correlated to the injection rate. Then, the ratio of matrix recovery to heptane injected was correlated to the newly defined dimensionless group (fracture diffusion index, FDI). The FDI is the ratio of fracture flow parameters (viscous forces) to matrix diffusion parameters. A critical FDI that maximizes the oil recovery while minimizing the amount of the injected fluid was defined. The process efficiency in terms of the time required for the recovery instead of the amount of solvent injected was also investigated.
It is expected that the experimental results and the dimensionless group, FDI, will be useful in deriving matrix-fracture transfer function for diffusion that is controlled by the flow rate, matrix and fluid properties.
Prediction Equation of CO2 Corrosion With the Presence of Acetic Acid
Authors: Ismail M. C. , Turgoose S. 
Published: December 2007

Abstract
The presence of organic acid species in formation water of oil and gas reservoirs has long been suspected to contribute to the corrosivity of the system under CO2 corrosion. The effect had been regarded as secondary until new findings in the 80's and 90's revealed the increase in corrosion rate in CO2 environment with the presence of acetic acid species. This is potentially detrimental as most of the predictive models used in corrosivity assessment of the field do not incorporate considerations of the effects of acetic acid species. This paper presents experimental corrosion rates of carbon steel in CO2 environments with the presence of acetic acid species in stagnant and low flow conditions, based on linear polarisation resistance (LPR) analysis. The experimental corrosion rates are compared with the corrosion rates predicted by industrial predictive models such as NORSOK and Cassandra. Based on the findings, we can conclude that acetic acid species increase the corrosion rate of carbon steel in CO2 corrosion substantially and standard predictive models do not capture this effect. A prediction equation is proposed to cater for the presence of acetic acid in CO2 corrosion under stagnant and low-flow conditions.
Technology Development and Field Testing on North Slope Leads to Improved Reliability of the One-Trip Sand-Control Completion System
Authors: Garfield G. L. , Hoffman C. R. 
Published: December 2007

Abstract
This paper discusses the evolution of a one-trip sand control completion system that is designed to eliminate or reduce causes of formation damage and improve performance. The new system provides the means to deploy the production liner, creates connectivity with the reservoir without the need of explosives, provides effective sand control, and offers zonal isolation, all in a single trip.
In the early stages of development, the procedure utilized a telescoping conduit that was designed to be extended hydraulically and/or mechanically. As a result of extensive lab tests and field trials on the North Slope of Alaska, hydraulic extension has proven to be the preferred method. The authors will demonstrate design improvements implemented to improve the overall reliability and efficiency of the new system while reducing rig time. In addition, the authors will illustrate plans to simplify operational logistics, especially in remote or offshore environments, as a direct result of the field trial in Alaska. The new completion method also eliminates gravel packing, minimizes the amount of intervention into the well completion, is not dependent on large fluid pumping treatments nor does it require excessive pumping horsepower, and saves substantial rig time due to its one trip operation.
This paper describes initial lab and field test results of the new system, cost comparisons with existing methods, and expected economic benefits over the lifetime of wells in typical applications of this new technology.
Reservoir Permeability: Innovative Measurement Based on Novel Concept
Authors: Belhaj H. A. , Mousavizadegan S. H. , Ma F. , Islam M. R. 
Published: December 2007

Abstract
A new model of permeability to clarify the true behavior of fluid flow around producing wells is presented. A two-dimensional representation of fluid flow in the reservoir is inadequate in many ways. The direction of fluid flow in the reservoir is neither horizontal nor vertical, and consequently the traditional use of these two permeability components in determining fluid flow characteristics has been misleading. Rather, fluids flow from all parts of the reservoir and converge to the wellbore, a very small spot in a big reservoir. The flow pattern towards the wellbore takes a conical shape where the base of the cone at the reservoir boundary and the head is at the wellbore. In many cases, the flow reduces to the perforations which are even smaller "ports" compared to the huge reservoir.
The need for a three-dimensional permeability becomes significant, and this term, complete with a technique for measuring it, is introduced here. A new method developed for determining the 3-D (conical) permeability presented and discussed. The proposed method is based on Darcy’s Law employed in a hemispherical scheme as the released gas flows from the probe through the sample in this pattern. The derivation of the model used along with the numerical technique utilized for solving are presented as well. Predictions of the model for air flow into a porous system are presented that appear to conform to the authors’ vision of fluid flow in petroleum reservoirs.
This new 3-D (tapering) permeability term should enhance the accuracy of the models used to represent fluid flow in porous media.
Experimental Evaluation of Formation-Strengthening Potential of a Novel Gel System
Authors: Amanullah Md. , Boyle Richard 
Published: December 2007

Abstract
The strengthening of near wellbore unconsolidated sand formation can play a vital role in reducing sand erosion, sand failure, formation compaction and other borehole problems. The strengthened formation is expected to tolerate higher surge and swabbing pressures leading to a reduction in trip-time failure of unconsolidated and poorly consolidated sand formations. The enhanced formation strength may allow sufficient tolerance to overbalance pressure leading to the use of higher mud weight due to the widening of the mud weight window. Adequate strengthening of the near wellbore formation may also create geo-mechanical condition for underbalance drilling. Different chemicals and polymers can be used either alone or as a part of drilling mud to invade and enhance the near wellbore formation strength characteristics. This paper describes the experimental results of a novel gel system used in improving the strength characteristics of a 16/30 sand pack representing a highly unconsolidated sand formation.
Visual observation shows that the novel gel system is capable to bind the loose sand particle together to create an integrated sand mass with good physio-mechanical consistency. Experimental results show more than 50% increase in the penetration resistance of the sandpack compared to a simulated pore fluid saturated sandpack. The gel has thermal stability up to 100 °C. Hence, its inter-particle bonding and strengthening capability will cease for formation having temperature above 100 °C. However, the gel could be potential candidate for some improvement of the near wellbore formation strength properties up to a depth having a temperature less than or equal to 100 °C. The gel is environment friendly, economically attractive and needs no cross-linking agent for bonding and networking to improve the formation strength.
Successful Use of Multipurpose Vessel for Well Intervention and Stimulation, The Means to Manage Brownfield: Case History
Authors: Al-Araimi N. , Queirós J. , Chan Keng Seng , Samuel M. 
Published: December 2007

Abstract
The continuous and increasing demand for oil and gas coupled with already recognized Brown Field stage of many of the major producing reservoirs led the operating companies to re-focus their attention on quick incremental production gains to supplement the drilling activity. These conditions promoted the interest for well intervention and stimulation in Brunei. The arrival of a multipurpose rig capable of handling the operating environment facilitated this intervention in the shallow water offshore of Brunei.
This paper demonstrates the impact on the so called Brown Field of shifting the focus from field development to incremental production recovery. It will address the importance of vessel and well candidate selection processes, fluid selection and in particular, the well flow back as a critical stage to maximize well performance. Case histories are used to formulate and offer technical process recommendations for well intervention activities with consolidated experience of project undertaken by Brunei Shell Petroleum (BSP) during the Coil Tubing Stimulation campaign of 2004/05, assisted by the multipurpose service vessel BIMA. It discusses the challenges encountered, the advantages of selected operating vessel and its impact on delivering the expected results.
Resolving the Right Support-Vessel Strategy for Offshore Coiled-Tubing Operations
Authors: Mahajan Mahesh 
Published: December 2007

Abstract
Whilst the coiled tubing technology continues to emerge as a versatile solution in the industry, it is often perceived as an expensive option by many operators. Offshore coiled tubing operations are usually more challenging than land CT operations due to involvement of several additional issues like requirement of Support Vessel, tighter equipment lay-out, higher lifting capacity requirements on site, sensitivity to weather/sea conditions etc. which may also have significant cost implications. With the expanding drilling limits in respect of operating depths, well trajectories, down hole pressures, hole sizes and other operating environment, the resulting wellbores are becoming increasingly challenging to down-hole service operations. The inability of the conventional ways of down-hole intervention like slick-line and e-lines to service such wellbores is opening up newer dimensions for coiled tubing applications. To cater to these increasingly challenging expectations, the coiled tubing size is gradually expanding and the length is extending, both demanding higher lifting capacities and bigger space on location.
There are various ways offshore coiled tubing operations can be managed, in some cases, even without a support vessel. However more often a support vessel is required for running smooth operation. There are various types of support vessels available in market from tiny little workboats to highly sophisticated service vessels. The economics of any support vessel strategy are often mistaken; a low cost vessel may not necessarily be an optimized solution in terms of the overall economics of operations. In continuous operations, it is also common to see that sometimes the rate of coiled tubing servicing over takes the rate of generation of work-load, thereby creating the situation of resource idling.
The present work demonstrates an analytical approach in formulating the right strategy on support vessel for offshore coiled tubing operations. It compares and evaluates various alternative modus operandi of running offshore coiled tubing operations and work its way up to identify the most appropriate strategy in terms of overall economics and safety considerations. The work also evaluates the sensitivity of this strategy on several technical, operational, organizational and environmental parameters, which commonly surround the actual working environment.
Polymer Reduction Leads to Increased Success: A Comparative Study
Authors: Kostenuk N. H. , Gagnon P. J. 
Published: December 2007

AbstractRecent advances in guar and cross-linker technologies have resulted in the development of high viscosity cross-linked borate fracturing fluids without increasing polymer loadings. These Low Polymer borate fracturing fluids (LP) are successfully being utilized in various formations previously believed to be too hot and or too deep for low polymer fracturing fluids.Historically, polymer loadings of 3.6 – 4.2 kg/m3 (30-35 lb/1000gal) were commonly pumped in the Western Canadian Sedimentary Basin (WCSB) for formations deeper than 2500 meters and bottom hole temperatures greater than 80°C. These same formations are now fracture stimulated using the Low Polymer fluids with loadings as low as 1.8 kg/m3 (15 lb/1000gal) with exceptional results.This paper demonstrates that Low Polymer fracture fluids can be used in place of higher polymer fluids with minimal changes to the overall design of the fracture treatment. The new fluid can be pumped on-the-fly at conventional pump rates and proppant concentrations due to the fluid's improved shear and temperature stability.The advantages of using a reduced polymer fracturing fluid include increased production, lower treatment costs, and lower friction pressures.This paper illustrates these advantages as it compares the Low Polymer fracture fluid with High Polymer fracture fluids in over 200 wells in the WCSB. The formations where LP fluids were utilized have depths of up to 3250 meters and reservoir temperatures reaching over 100°C.