bluuebunny/crossref_metadata_2025_split huggingface dataset:
Planning and Procedures for the Initial Startup of Subsea Production Systems
Authors: Duhon H. J. , Garduno J. L. , Robinson N. A. 
Published: October 2009

Abstract
Initial startup of a subsea development is one of the most challenging periods in the operational life of the facility. Many issues complicate this period. These include: –People issues: a great many people from many teams are required to execute a startup; roles and responsibilities may be unclear and will change over the course of the startup; persons on board (POB) issues limit the number of people who can participate; personnel involved may not be fully trained in the operation of the facility.–This will be the first time much or all of the equipment is used in live hydrocarbon service. Design flaws, commissioning omissions and infant mortalities will rear their heads.–Preserving completion integrity requires low rates and slow bean-ups during initial startup because of high formation skin. Chokes designed for high rates and low pressure drops may not be capable of controlling the well at low rates. Also, topsides systems designed for peak rates may not function well at low flowrates.–Low flowrates and low initial temperatures result in hydrate risk which may challenge the flow assurance strategy.–Completion and stimulation fluids returned during the initial well cleanup are corrosive and are difficult to treat. Specialized water treatment equipment is typically installed temporarily on topsides to treat these fluids.–Solids from the reservoir and from construction debris may cause problems such as plugging small ports in control valves.–Drilling, construction, installation and commissioning activities (SIMOPS) may still be in progress. The exact state of equipment items may be unclear and may change over the course of the startup.–Special procedures are usually written for the initial startup. These will differ in important ways from the normal operating procedures. Risks exist that there may be errors in the startup procedures, that operators may err in implementing the procedures, that equipment designed for normal operating will not function well at the conditions imposed by the startup.–Reservoir Engineers will seek to obtain reservoir information via well tests, especially pressure build-up tests. These tests are sensitive and are easily disrupted by operator actions during the tests.–Some regulatory requirements apply specifically to the startup period.
Careful planning is required to achieve a trouble free startup. This paper describes the key requirements for generating effective startup plans and procedures.
Modernization of the SEC Oil and Gas Reserves Reporting Requirements
Authors: Lee W. John 
Published: October 2009

Abstract
Modernized US Securities and Exchange Commission (SEC) rules for reporting oil and gas reserves are now broadly consistent with the SPE definitions and generally reflect public requests for specific changes in the previous rules. Disclosure requirements based on the revised definitions feature use of annual average prices; wider use of reliable technologies; broader recognition of nontraditional resources, including those from oil sands, shales, and coal; optional disclosure of probable and possible reserves; and replacement of the "certainty" criterion for some reserves by a "reasonably certain" criterion. Official clarification of some of the new terms may be forthcoming; here, I provide my opinion of their intent.
Coupled Reservoir Flow Simulation: Fault Leakage Analysis
Authors: Rodrigues L. G. , Cunha L. B. , Chalaturnyk R. J. 
Published: October 2009

Abstract
Petroleum project costs may increase tremendously if wells need to be shut in or abandoned. A scenario where this possibility exists occurs in a reservoir hanging a major fault that connects the petroleum field to the seafloor. During water injection operations the fluid pressure within the fault may increase to a value that leads to fault slip and hydrocarbon flow through to the seabed. The hydrocarbon leakage can result in severe environmental damage and must be avoided. So, a proper simulation model that enables the evaluation of the maximum injection pressure allowed to impede oil leakage during water injection projects is a necessity.
The focus of this work is an offshore unconsolidated sandstone reservoir field located in Campos Basin, Brazil. This field has used waste water for injection since the beginning of production, and there are strong uncertainties about the limits of pressure injection and reservoir fault properties that are related to the project development.
To achieve the objective of examine uncertainties of flow through a major fault in offshore oil reservoir undergoing waterflooding; a methodology is developed that enables the incorporation of key mechanisms (e.g. effective stress law) and parameters (e.g. volumetric strain) to solve a complex numerical field reservoir simulation problem that includes geomechanical process. The proposed methodology uses an external-iterative-coupled reservoir-geomechanical modeling approach to capture the link between fluid flow and in situ stress.
As a conclusion this study will reveal the effects of dynamic changes of permeability and porosity on reactivation of faults in a real offshore reservoir (Field "A"), and set up a minimum safe water pressure injection level for the field.
The methodology developed in this study is valuable for assessing other oil exploitation project scenarios where limited information and production uncertainties are present. This work is important for reservoir characterization, enhanced oil recovery and production applications such as oil rate leakage through a fault.
Combination of Chemical Diverters and Degradable Fiber Technology Enhances the Success of Stimulation in Complex Carbonate Environments
Authors: Dashti Qasem , Liu Hai , Cirrincione Todd , Al-Saqabi Mishari , Lesko Timothy M. , Majid Azmin A. 
Published: October 2009

AbstractDue to damage caused by drilling and completion operations, most wells in the Jurassic carbonate reservoirs in North Kuwait require acid stimulation after perforating to either recover or enhance the well productivity. To date, production responses after stimulation treatments have been mixed, depending on the formation, the type of treatment and the volume and the chemistry of stimulation fluids. Additionally post-stimulation production logging surveys in many wells typically have shown poor stimulation efficiency with only a short perforation interval contributing to a majority of the production. Thus, it becomes crucial to develop general engineering guidelines and address treatment diversion issues for future stimulation work.This paper presents an engineering process for optimizing matrix stimulation and acid fracturing treatments according to laboratory tests and well performance evaluation in more than 20 wells in the deep Jurassic carbonate reservoirs in Kuwait. The paper also introduces a new stimulation technique that combines chemical diversion (viscoelastic surfactant based diverting acids) and degradable fiber technology to enhance leakoff control and diversion capability of the chemical solution into the complex naturally fractured carbonate formations. The technique improves leakoff control into large natural fractures, dominant wormholes and high permeability zones, and results in deeper acid penetration and more effective vertical coverage. The degradable fibers completely decompose with time and temperature after the treatment has been pumped.Field results have shown significant improvement of post-stimulation production after the general engineering guidelines were implemented. Application of this new stimulation technique has been evaluated through the production surveys and performance before and after the treatment. Initial results on the first well showed an eightfold increase in the productivity index.
Are there Less Costly Ways to Sequester Carbon than CCS?
Authors: Gupta Subodh 
Published: October 2009

Abstract
Given the expected rise in global demand for energy, which in turn is dominated by reliance on fossil fuels, carbon emissions are only expected to increase, raising the CO2 concentration of the atmosphere even further. Efficient use of energy will help but if we have to reduce atmospheric CO2, we are forced to consider methods of carbon sequestration and associated costs. Carbon Capture and Storage (CCS) is the most discussed method of sequestration. However, there are two major issues with this approach of sequestration. Firstly, it is the high direct cost associated with capital and operation of capture, transport and subsurface injection. And secondly, it is the undetermined cost of post-operation liability associated with measurement, monitoring, verification and problem-rectification. Committing to the needed large scale sequestration projects without properly considering alternatives can prove costly at both economic and social levels. There are alternatives to CCS, however. Use of biomass derived fuels such as bio-ethanol has been talked about in literature as one of them. But biofuels are shown to be more expensive for carbon abatement than the base alternative.
Charcoal sequestration (CS), discussed earlier by the author carries with it the benefit of being a pure sequestration (similar to CCS), is less costly both in terms of its direct costs and lacking any post operation liabilities, and above all is reversible, allowing flexibility of policy and operation, avoiding long term or large scale commitments.
In this paper the author outlines how municipal solid waste (MSW) processing into charcoal can be a good way to initiate demo projects for charcoal sequestration approach potentially opening door for employing other larger resources of biomass and shows as such use of MSW has to be a major component of our carbon abatement package of actions. This is for reasons of both cost effectiveness as well as to reduce the landfill methane (a more potent GHG) from entering into atmosphere. The over all discounted cost of a suite of proposed measures including improvement of efficiency, conversion of waste to charcoal for use both as fuel as well as sequestration, increased use of nuclear energy, limited application of CS using larger dead-stock biomass pool, and CCS, is assessed to be in the range of US$7.5trillion in this paper, reducing the equivalent CO2 concentration by 465 ppm (compared to the projected business as usual) by the end of 21st century.
The outlined approach, with its prominent use of MSW, promises not only to mitigate the growing urban waste problem but also to help evaluate this novel method of sequestration and enhance public awareness on the subject. This in turn will help the larger society make an informed choice to embark on a right course of action for atmospheric carbon abatement.
Wellbore Profiling With Broadband Multipole Sonic Tools
Authors: Market Jennifer , Canady Wyatt , Elliott Paul , Hinz David 
Published: October 2009

Abstract
Theoretical papers have been presented considering the depth of investigation of classic sonic tools, largely focusing on the effects of the source-to-receiver spacing in the case of altered zones. Modern sonic tools use multipole sources (monopole, dipole, and/or quadrupole) at a broad range of frequencies and source-to-receiver offsets. This paper briefly reviews the theoretical discussions of the effects of tool geometry and source characteristics, but focuses primarily on the practical aspects of wellbore profiling with modern sonic tools. We concurrently consider the tool geometry, source order, and frequency effects on the depth of investigation and discuss the differences in wireline and logging-while-drilling environments. Multiple field examples are shown in cases of alteration and invasion. We explore the benefits of reporting sonic logs at multiple depths of investigation, which can yield valuable information about shale reactivity, wellbore stability, and geosteering. A summary of how to recognize the effects of variable depth of investigation on common sonic logs presentations completes the report.
A New EOR Method
Authors: Behzadi S. Hamid , Towler Brian F. 
Published: October 2009

Abstract
A new method of enhanced oil recovery has been developed and applied to a sector simulation using some of the data from the South Slattery Field, Minnelusa A reservoir. The new method, termed ASPaM, combines features of CO2 miscible flooding with Alkaline-Surfactant-Polymer (ASP) flooding to produce an enhanced WAG flood. A numerical pre-processor program had to be developed to produce the required mixing zone properties of a CO2 front, which are input to the CMG simulator, STARS. STARS is a chemical flood simulator, but cannot accomodate the solvent model. The preprocessor calculates oil and solvent properties based on the Todd-Longstaff procedure. Sensitivity analysis showed this new method can give a much better recovery in comparison to ASP or CO2 WAG flooding for different depositional environments. ASPaM benefits from high micro and macro sweep efficiencies plus miscible flooding, even for a small ASP slug size. The simulation results revealed the recovery from this scheme is considerably better than ASP and CO2 flooding separately. It showed the recovery can be improved and accelerated by the application of ASPaM, and its performance is a function of the miscibility of the CO2-oil miscible zone and the reduction in IFT at the ASP-oil interface at reservoir conditions. Moreover the water/gas ratio of ASPaM is totally different in scale compared to a typical WAG scheme. A significant acceleration and improvement in recovery is achieved with a 10 % pore volume ASP slug size. This work indicates CO2 flooding and sequestration can be stabilized and enhanced if it combines even with a small ASP slug size. The results so far have been very encouraging.
Distribution of Hydrogen Sulphide in the Buzzard Field
Authors: Beilby P. , Clayton C. , Moffatt B. 
Published: October 2009

Abstract
The Buzzard field, discovered in 2001, is an Upper Jurassic turbidite reservoir lying in the outer Moray Firth of the North Sea. It has an estimated STOIIP in excess of 1 Billion STB.
During the appraisal drilling the fluid properties were found to be generally similar across the field with the exception of the H2S, CO2 and Mercaptan levels. During initial development drilling, using improved measurement techniques, the H2S levels were found to vary more than originally predicted.
Extensive geochemical studies were performed to ascertain the charging mechanism. The results suggested that the H2S was present in the original charge oil, that the charge was very recent, and that the aquifer water was most likely having a significant effect in removing some of the H2S from the oil during migration. It was also thought that there was additional natural scavenging from the rock. These theories were also supported by equation of state modelling and stable isotope analysis.
The H2S data was mapped onto the geo-model and H2S levels were simulated and controlled using tracers in the dynamic model. The results were subsequently used to determine future well locations and to predict and control the field's producing H2S levels. Since the H2S distribution was determined, 10 out of 10 production wells drilled have been successful in targeting sweet oil. This drilling program has allowed the field ramp up and plateau to be unaffected by the more variable H2S distribution. To date the field has now produced more than 155 MMstb of oil with actual H2S levels being relatively close to predictions.
In summary improved H2S sampling and measurement techniques, geochemical modeling, EOS modelling and mapping in conjunction with simulation have provided a robust solution to aid effective field development.
The Piston Tubing Rod Performance Curve: A New and Useful Concept for Sucker-Rod-Pumping Analysis
Authors: Caicedo Sergio , Carma Suhail 
Published: October 2009

Abstract
Engineers have used standard techniques for decades when analyzing sucker rod wells, such as: API 11L standard, wave equation numerical simulation, acoustic logs and dynamometer card acquisition and processing. Each technique has a particular goal and they complement each other. API 11 was developed in the fifties as an easy and hand computation procedure for estimating the production and operational parameters (loads, stresses, torque, etc). Later in the eighties the desktop computers came into the market making the wave equation approach reasonable and popular. The acoustic logs and dynamometer card have been diagnosis tools in the field, which have been boosted by the portable computers. However, none of these tools is able to generate the pump performance curve equivalent to those provided by the electrical submergible pump (ESP) or progressive cavity pump (PCP) manufacturers. Piston pump manufacturers cannot generate that curve at the factory because they only can measure the pump's slippage (leaks in valves and piston walls) but the pump performance also depends on the following parameters: rod and tubing stretching, the rod fundamental frequency, which change in each completion. In the present paper the approach and algorithm to generate the Piston-Tubing-Rod Performance Curve (PTRPC) is shown, which gives a new complementary tool for engineers. Some examples show usefulness of this innovative concept in Sucker Rod Pumping. Finally, the way to introduce the PTRPC in a Nodal Analysis is presented.
Laminated Sand-Shale Formation Evaluation Using Azimuthal LWD Resistivity
Authors: Bootle Richard , Waugh Matthew , Bittar Michael , Hveding Frode , Hendricks William E. , Pancham Shivanand 
Published: October 2009

Abstract
Intervals of thinly bedded hydrocarbon-bearing sands and laminar clay cannot be fully evaluated with conventional log measurements and interpretation techniques. This is because the laminar nature of the clay component suppresses the logged deep resistivity measurements and results in calculated values of water saturation that are artificially high. This formation evaluation challenge is already widely recognized by the industry and addressed by an interpretation solution that uses simultaneous measurements of horizontal and vertical resistivity, available from the new generation of wireline induction-resistivity tools.
A newly deployed logging-while-drilling (LWD) sensor now provides equivalent measurements of azimuthal resistivity; this technology was deployed for the first time for the formation evaluation of thinly bedded sands in Trinidad's Dolphin Field. This tool provides multiple depths of investigation and 32 azimuthal resistivity measurements. Horizontal and vertical resistivity are extracted from the multi-spacing and multi-frequency azimuthal data using fast and robust inversion algorithms. The results were validated with a back-to-back run with an equivalent wireline service.
An interpretation methodology is presented that sets out the equations used for the mathematical solution of these data. The Thomas-Stieber method is used to partition the calculated clay volume into its laminated, structural, and dispersed components and to calculate the effective and total porosity of the sand fraction of the reservoir. The corresponding true resistivity of the laminated sand fraction is derived from the quadratic solution of horizontal and vertical resistivity and the laminar clay volume. The water saturation of the sand fraction is calculated using the Archie Equation and subsequently volumetrically weighted to provide the total water saturation. The Thomas-Stieber parameters are also used to calculate the formation averages.
The high angle, high step-out wells drilled in this phase of field development have calculated hydrocarbon pore volumes of up to 33% greater than historic, near-vertical wells logged with conventional resistivity tools only. The results of the thin bed interpretation are observed to be sensitive to both borehole deviation and the stratigraphic interval.
Geomechanical Coupled Poromechanics Solutions While Drilling in Naturally Fractured Shale Formations with Field Case Applications
Authors: Nguyen Vinh X. , Abousleiman Younane N. , Hemphill Terry A. 
Published: October 2009

Abstract
Numerous wellbore instability problems have been reported when drilling through chemically active naturally fractured shale. It is usually accepted that wellbore collapses are caused by excessive effective stress concentrations at or near the borehole wall, and excessive mud losses are due to fracturing the rock formation. Since both the pore pressure differential and mud/shale chemical activity modify the effective stresses in the wellbore wall, the cures for such intricate instabilities are therefore in a wellbore solution that accounts for fractures, intact matrix mechanics, and the balance of mud density and salinity. In this work, the effects on collapse and fracture gradient window due to mud chemistry and densities are evaluated through the salinity, membrane efficiency, and the existing natural fracture network. The coupled poromechanics analytical solutions of fracture and matrix dual pressures and stresses predict large variations in the collapse and fracture gradient when compared to wellbore stability in non-fractured shale formations. The physical and mathematical solutions follow the coupled poroelasticity Biot theory through modeling fracture and matrix as dual-porosity and dual-permeability porous media. The solution is helpful in the prediction and visualization of time-dependent alteration of near-wellbore effective stress concentration and the effects on the mud-weight window when compared to non-fractured shale. Specifically, the solution is applied to assess wellbore stability for a simulated downhole drilling condition. Analyses that neglect the naturally fractured nature of the shale fall short in simulating wellbore instability since they predicted a narrower mud-weight window for the drilling operation, while the chemical and mud salinity effects can be utilized as a stabilizing factor.
Identification and Characterization of High-Conductive Layers in Waterfloods
Authors: Kabir C. S. , Izgec B. 
Published: October 2009

Abstract
This study expands upon the use of modified-Hall analysis to discern the characteristics of a high-permeability channel. Briefly, the modified-Hall plot uses three curves involving improved Hall-integral and the two derivatives, analytic and numeric. Ordinarily, the derivative curves overlay on the integral curve during matrix injection, but separates lower when fracturing occurs. This work presents a method to identify and characterize high-conductive layers or channels between injector and producer pairs with the modified-Hall analysis. The distance separating the integral and derivative curves provides the required information to quantify channel properties. A simple analytical solution is presented for transforming the separation distance into channel permeability-thickness product.
The analytic derivative is based on the radial-flow-pattern assumption and the numeric derivative is correlated to the pressure response. Therefore, a comparison of these two curves reveals clues about the maturity of a waterflood at a given time. Several simulated examples verified the channel-property-estimation algorithm and identified the distinctive derivative signatures for channeling and fracturing situations. This methodology is also useful for identification of wormhole propagation during sand production in unconsolidated formations.