bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Simplified Model for Oil-Water Flow in Vertical and Deviated Wellbores
Authors: Hasan A.R. , Kabir C.S. 
Published: December 2007

Abstract
This paper presents the results of an experimental study and a semitheoretical analysis of two-phase oil-water flow in vertical and deviated systerns. The study focuses on water- dominated flow regimes, where the patterns may be termed as bubbly flow, pseudoslug flow, and churn flow. A drift-flux approach is taken to analyze the flow behavior of oil-water systems. For the three flow regimes investigated, the drift flux of the lighter oil phase is found to be dependent on its in-situ volume-fraction in addition to the terminal bubble-rise velocity. This behavior is in contrast to the gas-liquid flow, where the drift flux has often been found to equal to the bubble-rise velocity. For flow in both vertical and deviated pipes, we were able to develop a single expression for the drift flux, Uow, resulting in a single equation for the in-situ oil fraction, fo, for the three flow regimes studied. We correlated f0 with the oil superficial velocity, vos, and the terminal rise velocity, voo using the expression, fo=. In a deviated pipe, the terminal rise velocity, voo is correlated with that in a vertical pipe by.
The performance of the proposed method in estimating fo is in good agreement with our measurements. Published data further augment the approach presented here.
P. 493
Effective Reservoir Simulation of the McKee Field, New Zealand
Authors: Wadsley A. W. , Adams M. R. , Stoltz L. R. , Jones M. S. 
Published: December 2007

Abstract
The McKee Field was discovered onshore New Zealand in 1979 and brought to commercial production during 1984. Beginning with the early stages of development planning, each stage of the field's life has been actively guided by reservoir simulation. An early pre-development model was built in 1983, and full field simulation has been carried out, and routinely updated since 1986.
A review of the effectiveness of reservoir simulation as an ongoing planning and management tool for the McKee Field has been conducted. It is shown that reservoir simulation, even at the earliest stages, can act as an accurate model for determining optimum recovery processes and development strategies. Models must be continuously updated and refined to reflect the current best knowledge of the reservoir in order to remain effective at locating infill or re-completion candidate wells and at addressing the changing reservoir management objectives of the day. The ability of the model to accurately predict future field performance, is shown to be directly related to how well the simulation model represents reservoir geology, and structure, and the consequent relative ease with which a history match has been obtained.
The simulation technology applied has evolved, in order to accurately represent the improving state of reservoir knowledge with time, from conventional cartesian gridding with vertical faults used in 1983 and 1986, through corner-point geometry applied in 1988, simple polygonal gridding first applied to full-field modeling in 1991, to the complex polygonal full field model with explicit over-thrust and multiple back-thrust fault matching in use today.
The current simulation model is both a dynamic fluid-flow model and a detailed 3-D geological model of the reservoir. It includes a comprehensive representation of stratigraphy, permeability anisotropy, and all mapped faults with as-mapped dips and strikes. This model is currently used to plan infill drilling, water-flood, for appraising tertiary gas flood and WAG, and for managing aspects of production optimization.
A New System To Enhance Production of Mature Wells
Authors: DeGhetto G. , Paone F. , Nielsen K.L. , Villa M. 
Published: December 2007

Abstract
The paper presents, focusing on the field experience, an innovative system aimed at increasing the production rate of mature wells that exhibit low well head flowing pressure.
The system is essentially constituted by a normal centrifugal pump, fed by live oil coming from an existing separator, which activates a multiphase ejector that "sucks" the mature well/wells. The separator can be fed by other wells or by the same boosted well in a short circuit way.
The innovative system was eventually applied in field after a four years R&D project.
The field results are extremely good showing an increase of the oil rate of one well by more than five times: production before was 0 - 200 bopd (fluctuating), production after was 1000 bopd stabilized, with a decrease of the flowing well head pressure of 200 psi.
Costs: CAPEX 300.000 $, OPEX 1$/bbl, pay out time about 1 month.
The paper will report and analyze the results of this application and discuss the potential use of the system in various scenarios for boosting low well head pressure oil wells.
P. 501
Emulsification of Production Fluids in the Choke Valve
Authors: van der Zande M.J. , Muntinga J.H. , van den Broek W.M.G.T. 
Published: December 2007

Abstract
For oil production under high water cut conditions the efforts needed for de-oiling of the production water are mainly determined by the oil-droplet-size distribution of this water. This distribution is predominantly the result of droplet breakup in the choke valve. To determine the effect of the choke valve on the droplet-size distribution, we have conducted laboratory experiments in which we used a circular orifice in a circular pipe. With the help of theory on droplet break-up in turbulent flow and with knowledge of the flow field inside an orifice, a prediction of the distribution after break-up can be made. It is shown that the droplets increase in size with increasing oil viscosity and furthermore it appears that, for the description of the break-up process, the distribution of the turbulence over the orifice zone is an important factor.
P. 525
Applying Log-Constrained Seismic Inversion Technique To Optimize the Development of an Offshore Marginal Oil Field
Authors: Meifang Tang , Shuling Sui , Jun Wang , Jiquan Yin 
Published: December 2007

Abstract
Chengdao Oilfields is located in Bohai Bay of East China. The Oil-bearing sandstones are fluvial sediments of Tertiary upper Guantao Member. The sand bodies change rapidly both in thickness and lithology. It results in quite different productivity between the wells. Development of the oilfield needs high investment with low economic efficiency, and will be full of risks.
In order to predict the distribution of the sandbodies and its petrophysical properties to optimize the well locations, a stratigraphic research using log-constrained seismic inversion technique was conducted. By means of improving the processing methods, the stratigraphic wave impedance data with high resolution and accuracy were obtained. According to the relationship between the wave impedance data and the reservoir properties, the lateral changes of the reservoir and it's petrophysical properties were disclosed.
Based on this results, 86 wells have been successfully drilled in areas with thick reservoir. Comparing with expected number and thickness of the layers in individual wells, the well numbers with errors less than 20% are 74 (86%) and 67 (78%) respectively. It makes the previous marginal oilfield to be a cost effective recoverable oilfield.
This paper presents the research concerned and it's results.
P. 557
Coupling Financial Profit Indicators to a Net Cash Flow Model for Production Sharing Contracts
Authors: Thompson Robert S. , Wright John D. 
Published: December 2007

Abstract
With the increased emphasis on shareholder earnings and financial "profit," project evaluators are facing more questions about the impact of projects on financial net income. This paper demonstrates a method of coupling traditional project net cash flow analysis to incremental project pro forma financial statements for a production sharing contract. The coupling of a project net cash flow model with pro forma financial profit indicators provides an additional measure of profitability and information that may enhance project selection. In production sharing contracts, the cost recovery feature may enhance incremental project financial net income in early project years when intangible expenditures are significant.
P. 567
An Innovative Technique of Obtaining Project Financing for the Equity Share of a Developing Country's National Oil Company
Authors: Schaaf Robert P. 
Published: December 2007

Abstract
It is not uncommon for the National Oil Company (NOC) of a developing country to encounter difficulties in obtaining project financing. Due to the instability of their economies, credit is often reduced or withdrawn. If granted, credit is typically underwritten by proven reserves. However, the funds flow problem becomes acute as a larger and larger portion of existing reserves is provided to collateralize debt. This dilemma might be circumvented by switching to financing structures derived through the use of the NOC's share of existing or proposed surface facilities as debt security.
While the concept seems simple in theory, the application of potential components of this type of financing can prove to be quite complex. Various elements must be considered in the equation determining the optimal borrowing terms. The inability to resolve or mitigate certain issues - political instability, facility life and alternative uses, operational hazards, existing production questions, taxes, and de facto partial ownership of assets by a financial institution - is the primary reason the technique has not been widely developed and utilized.
In order for favorably resolved issues to prove useful, they need to be presented in a manner acceptable to the financial institutions. Additionally, requests for financing must fit within the funding parameters of the chosen financing source. Therefore developing a loan package that is palatable to the large financing syndicates will often prove a rigorous and daunting task. However, executed properly, this effort can release previously unavailable funds.
The Application of Novel Wax Divertor Technology to Allow Successful Scale Inhibitor Squeeze Treatment into a Sub Sea Horizontal Well, North Sea Basin
Authors: Jordan M.M. , Edgerton M.C. , Cole-Hamilton J. , Mackin K. 
Published: December 2007

Abstract
This paper presents field results from two scale squeeze treatments carried out on the same sub sea horizontal well from a field in the North Sea, The initial squeeze was a bullhead application of phosphonate scale inhibitor to control a sulphate scale problem in a horizontal well. Ten months after the initial treatment a second bullhead squeeze treatment was applied in two stages. This utilised a thermally degraded pelted wax divertor to temporally impair injectivity in the heel region of the horizontal well thus allowing propagation of the second stage of the squeeze treatment into the mid section of the horizontal well.
This paper will show the significance of production logging tool data toevaluate the location of deposited scale and water production prior to a squeeze treatment. Such data was used to design a novel two stage squeeze treatment in which an initial squeeze slug was applied to the heel region followed by application of a pelted thermally degraded wax divertor to prevent further loss of scale inhibitor to the heal region. The action of the divertor allowed a second scale inhibitor to the heel region. The action of the wax divertor allowed a second scale inhibitor slug to be placed further along the horizontal section of the well. Details of divertor selection and the squeeze design strategy implemented in this squeeze treatment will be presented. During the field treatment, physical (downhole pressure and temperature) data and chemical (non-radioactive tracers, inhibitor and ion Concentrations) data were recorded. This data will be used to indicate the success of diversion treatment by comparison with the first squeeze applied to the same well ten months previously.
This is the first successful application of a thermally degraded wax divertor to a subsea horizontal well in the North Sea basin. The well was successfully treated with no process up set during flowback and no decline in well production whilst allowing the well bore to be protected from continued sulphate scale formation. This paper clearly shows that with the correct selection of both scale inhibitor, divertor agent together with the utilisation of all available information relating to the reservoir. It is possible to squeeze scale inhibitors into sub-sea horizontal wells without the need for expensive coiled tubing intervention from a diving support vessel. This technology is not limited to horizontal wells and could also be applied tovertical wells with significant cross flow problems to aid in selective placement during scale inhibitor squeezing.
P. 633
A Wellbore Model for Predicting Aspholtene Plugging
Authors: Kocabas I. , Islam M.R. 
Published: December 2007

Abstract
Asphaltene precipitation can have profound effects on oil production during miscible flooding, heavy oil recovery, or even primary depletion. Even though asphaltene precipitation has been known to have strong effects on permeability reduction, quantitative analysis of the process has been started only recently. This paper extends the previous work to consolidate some of the hypotheses and develops a comprehensive wellbore model. The wellbore model couples the asphaltene adsorption model with a series of phenomenological models that are independently validated with either experimental or field data. These models are incorporated into the mathematical model, for a linear as well as radial system. The radial model is particularly useful for simulating asphaltene transport and deposition near the wellbore because of the continuously changing speed for this case. Intially, the governing equations were solved analytically in order to observe the role of some of the parameters independently. Following this, a series of numerical runs was conducted to observe the role of various governing parameters on wellbore parameters under more realistic representation.
Experimentally, the deposition was found to be a function of permeability, flow rate and concentration. Two distinct mechanisms were identified, namely, deposition and adsorption. Deposition could be explained in terms of trapping and mechanical plugging. The model builds on the two mechanisms described above. The coupled mathematical model predicts permeability damage due to mechanical trapping and adsorption accurately, as evidenced when compared with experimental results. Three different plugging regimes were identified and were verified with the numerical model. A series of predictive runs further clarified the transition between different flow regimes.
This paper offers readers with the first wellbore model that uses irreversible thermodynamics to model adsorption and desorption and couples it with a comprehensive mechanical trapping model. The simulator applies to all reservoirs with asphaltene problems.
P. 671
Problem Diagnosis, Treatment Design, and Implementation Process Improves Waterflood Conformance
Authors: Love Tracy , McCarty Andrew , Miller Matthew J. , Semmelbeck Mark 
Published: December 2007

Abstract
The Eunice Monument South Unit (EMSU) produces from the Grayburg formation in southeast New Mexico. The unit has higher than expected water production and lower than expected oil production since a waterflood was installed in 1986; poor vertical flood conformance is to blame. A major project was initiated in 1996 to characterize the reservoir and improve the flood conformance where possible.
Reservoir characterization included mapping high permeability streaks, material balance, and percent pore volume swept calculations. Two techniques, production data diagnostics and injection well diagnostics, were then applied to characterize the performance of individual wells. The subsets of wells that were identified as underperforming by each method were compared and a focus area was selected to pilot test a waterflood conformance correction program. Primary problems discovered included water cycling through high- permeability streaks, water injection into the gas cap, and wellbore zonal isolation problems.
The waterflood conformance correction program comprises problem diagnosis, treatment selection and design, treatment execution, and treatment evaluation. Several different treatments (cement squeeze, near-wellbore gel treatment, and deep-penetrating gel treatment) were executed depending on the problem encountered. This program has been implemented on 29 wells in EMSU. Production response to the treatments is discussed.
P. 689
Using Radio Frequency Identification Electronic Chips to Effectively Control the Elements of the Drillstring
Authors: Sampaio J.H.B. , Placido J.C.R. , Ferreira S.N. 
Published: December 2007

Abstract
The identification of drillstring elements (in particular drillpipes) is currently performed in PETROBRAS using serial numbers imprinted somewhere on the body of the element. A procedure will be set up to establish effective control of these elements, such as accumulated cycles, accumulated footage, inspection reports and, particularly, accumulated fatigue. It is necessary to track each element along all campaigns in which it takes part by identifying its position on the drillstring, registering the mechanical parameters it is submitted, and registering the mechanical conditions of the borehole. Using the traditional imprinted serial number, it is difficult (or almost impossible) to keep a reliable log of each drillstring element in the rig site. The use of electronic chips attached to the body of these elements allows a fast, efficient, and reliable identification of each element through a unique key number. A manual reader is used to scan the chip and send the information to a local database at the rig site. The drilling parameters are obtained in real time through sensors distributed along the rig and sent to the database. At given time intervals, these data are used to calculate the fatigue each element was exposed to and accumulate the data in the database. A suitable mathematical model then is used for the fatigue calculation. Before being connected to the drillstring, each element is checked for accumulated fatigue and is accepted or rejected depending on the expected fatigue it will be exposed to in the campaign. Integrated databases on the operative units control the stock, inspection reports, supply, purchase, and discard of the drilling elements. Elements used before the implementation of the system are considered dummy elements with respect to the accumulated fatigue and are treated as usual. New elements are tracked since the first drilling operation. A period of several years (the average life span of the elements) is expected until all old, untracked elements are replaced by new, tracked elements. Among several benefits, this procedure is expected to significantly decrease drillstring failure due to mechanical fatigue, with consequent associated cost savings.
P. 619
Torsional Resonance of Drill Collars with PDC Bits in Hard Rock
Authors: Warren T.M. , Oster J.H. 
Published: December 2007

Abstract
Formations encountered while drilling oil and gas wells are not homogeneous. This requires drill hits to be capable of drilling the most difficult rocks in the interval rather than the "average" rock and can result in a significant penetration rate penalty for cases where a few hard streaks preclude the use of PDC bits. Bit manufactures are actively trying to improve materials and bit designs to provide more robust bits, but in many cases it appears that some type of drillstring vibration limits the use of PDC bits in these hard streaks. Extensive data from drilling tests conducted at Amoco's Catoosa test facility indicate that PDC bits are damaged very rapidly when they encounter certain hard rocks. The visual appearance of the damage suggests some type of vibration damage, but the normal cures for bit whirl and drillstring stick/slip do not seem to be very helpful. The analysis of nineteen wells where a downhole vibration sensor was run and PDC bits encountered severe damage indicates that torsional resonance of the drill collars could result in backward rotation of the bits. The observed vibration has been known to exist (in a theoretical sense), but is not recognized as a significant cause of PDC bit failure. The Catoosa drilling data shows conclusively that a wide range of PDC bits sustain this type of vibration when they drill hard rocks. Laboratory tests demonstrate that reverse rotation of PDC bits result in catastrophic Cutter failure. The evidence collected so far suggests that reverse rotation due to torsional vibration is probably the cause of the rapid damage in certain hard rocks, but this postulation has not been proven because the sensor used in the tests was not adequately sensitive to say positively that the bit rotates backwards.
P. 625
Using downhole dynamics to better understand the drilling process with positive displacement motors and PDC bits
Authors: LAMINE E. , LESEULTRE A. , ROBERTS D. , WALKER C. , JONSSON A. 
Published: December 2007

Abstract
Downhole dynamics is now better understood through the application of downhole instrumentation. Vibration measurements at the bit have given us a precise understanding of PDC bit behavior from stick-slip to backwards whirl with pendulum and packed hole rotary assemblies.
Many PDC bits are however run on downhole motors for directional and performance reasons prompting testing to be done with an instrumented bit below such motors. This paper will present how PDC bits behaved below low speed and high speed motors. Measurements were taken while drilling both in rotary and sliding modes and also with straight and bent housing motors to obtain results over a wide spectrum of motor applications. Besides the effects on bit performance this paper will present, for the first time, the actual characteristics of a positive displacement motor operating in a downhole environment. The subsequent integration of bit and motor design will lead to the development of a more efficient and reliable drilling system. The PDC bits tested incorporated a new three dimensional design so as to minimize downhole vibrations.
Modelling of Transient Two-Phase Flow Operations and Offshore Pigging
Authors: Lima P.C.R. , Yeung H. 
Published: December 2007

Abstract
Transient gas-liquid processes and operations involving pigging has been successfully applied in hard environments offshore Brazil for assure an efficient oil and gas flow.
These pigging operations are: wax control in deep water multiphase flowlines, water and condensate removal from complex offshore pipeline systems and the use of pigging inside the well as an artificial lift system. Despite of the tremendous success of these operations in the last years, they were performed just based on experience. A new subsea boosting system using gas and pig to transport the accumulated oil in the flowline is also proposed and evaluate. This paper describes some of these operations and a new model to simulate them.
A two-fluid model was developed to determine the transient behaviour of fluids during these operations. The derived one- dimensional set of equations for each flow pattern describe the flow of fluids in all regions. Semi-implicit finite difference schemes were used to solve the initial and boundary value problem for each phase of the pigging process: gas/pig injection, gas shut-in, slug production and gas flow out of the system. A significant improvement upon previous work makes unnecessary to track the position of the slug front. Lab and field data are compared to the results from the theoretical model.
P. 701