bluuebunny/crossref_metadata_2025_split huggingface dataset:
Investigation into Oil/Water Separation Problems Utilizing RTD Testing and Fluid Properties
Authors: McLelland W. Greg , Garcia Melissa 
Published: December 2007

Abstract
Given the large volume of produced water handled at Prudhoe Bay, the oil content of the water is a critical loss control factor. For a period of ten to twelve months, one separation facility experienced severe oil loss in the produced water, with instantaneous peaks of as much as 12,000 bbls/d. Difficulty in obtaining adequate primary separation, evidenced by unacceptable oil concentrations in the separator water draws, was exacerbated by completely overloading the produced water treatment system.
To identify the cause(s) of these losses, RTD (residence time distribution) tests were conducted on all low pressure separation vessels and tankage in the produced water treating system. In addition, a series of interfacial tension and surface tension measurements were made on the fluids to which various treatment chemicals had been added. These test results, when looked at in concert, gave clear insight into the problems being experienced with effective separation. The effective residence time of a vessel is dependent upon the properties of the fluids in the vessel and these properties should always be taken into account by the engineer trouble shooting a system.
P.129
Conditioning Geostatistical Models to Two-Phase Production Data
Authors: Wu Zhan , Reynolds A.C. , Oliver D.S. 
Published: December 2007

Abstract
A discrete adjoint method for generating sensitivity coefficients related to two-phase flow production data is derived. The procedure is applied to calculate the sensitivity of wellbore pressure and water-oil-ratio to reservoir simulator gridblock permeabilities and porosities. Using these sensitivity coefficients, an efficient form of the Gauss-Newton algorithm is applied to generate maximum a posteriori estimates and realizations of the rock property fields conditioned to a prior geostatistical model and pressure and/or water-oil ratio data obtained under two-phase (oil and water) flow conditions.
P. 205
Evaluation of Steam Injection Process in Light Oil Reservoirs
Authors: Dehghani Kaveh , Ehrlich R. 
Published: December 2007

Abstract
Feasibility of steam injection for three light oil reservoirs in different geologic settings has been evaluated. These were a waterflooded deltaic sandstone, a waterflooded vuggy dolomite, and a deltaic sandstone structural trap with a gas cap.
Optimization of steam injection to take advantage of individual reservoir characteristics is demonstrated.
For the deltaic sandstone, selective flooding of channel sands with upward fining porosity gave the best results. For the vuggy dolomite, a hybrid steamflood-steam stimulation process that maximizes conductive heating of bypassed oil was found to be best. For the structural trap. up-dip steam injection below the gas cap with down dip producers showed more recovery over gravity drainage. Sensitivities of each process to uncertainties in geologic and rock-fluid parameters were also investigated. The most influential parameters were identified for examining the quality of input data and the added value of information to reduce the uncertainties.
Recent advances in reservoir characterization and modeling tools enable us to predict the performance of a Light Oil Steamflood (LOS F) more accurately than in the past, considering details of reservoir geology, fluid phase behavior, and displacement process physics. This is demonstrated through re-evaluation of a project carried out in 1985 in the Buena Vista Hills field in California where initial modeling using then current methods predicted a successful project. The re-evaluation would have correctly predicted failure as a result of early steam breakthrough.
Results show that light oil steamfloods can be designed to take advantage of post-secondary oil saturation distribution. The resulting project may be carried out in a considerably different fashion than conventional heavy oil steamfloods.
P. 279
Effect of Temperature on Heavy-Oil/Water Relative Permeabilities
Authors: Akin Serhat , Castanier Louis M. , Brigham William E. 
Published: December 2007

Abstract
In the first part of this study, the accuracy of the JBN technique for the determination of heavy oil/water relative permeabilities, and the effect of temperature on relative permeabilities is examined by giving numerical as well as experimental examples. Using the JBN technique leads to a false temperature dependence of relative permeability curves. In the second part, we present unsteady state relative permeability experiments with initial brine saturation at differing temperatures conducted using South Belridge sand and heavy oil. A new three step experimental technique and an analysis procedure were developed to test the effect of temperature on relative permeabilities. In this technique, an ambient temperature unsteady-state relative permeability run is conducted in the first stage, and following that the temperature is increased twice (i.e. 1220F and 1500F). Two phase saturation profiles along the sand pack are measured using a CT scanner. A commercial black oil simulator, coupled with a global optimization code is then used to estimate two phase relative permeabilities. Experimental saturation profiles, differential pressure and recovery data collected from both the ambient and higher temperature data are used in the numerical model. It has been observed that a single set of relative permeability curves can represent both the ambient and high temperature parts of the experiment. This suggests that relative permeability is not a function of temperature at least for the systems and temperature ranges tested P. 329
The E-M Field, Offshore South Africa: Review of Probabilistic and Deterministic Calculations of Hydrocarbons in Place and Reserves
Authors: Kelly R. T. , Storer A. J. , Bardwell K. A. 
Published: December 2007

Abstract
A significant effort is expended in the estimation of hydrocarbons initially in place and reserves (by which we mean ‘technical’ reserves in this paper), but sometimes little effort goes into leaving a clear and concise audit trail for other users, perhaps as a result of the large number of contributors to what is, by necessity, a multi-disciplined activity. The case study discussed - the E-M gas field, offshore South Africa - highlights the pitfalls in commonly used deterministic and probabilistic methods and indicates the level of appropriate detail that can be applied to each stage of the process, with particular emphasis on those parameters of greatest uncertainty. From this case study, general conclusions about the methods under discussion can be drawn. Hydrocarbons initially in place are calculated from first principles with a rigorous audit trail (which should be normal practice). Geophysical, geological, petrophysical and engineering data from seismic interpretation to reservoir fluid description are reviewed in depth and analysed statistically to ascertain appropriate distribution functions. Judgement calls are inevitably a necessary part of the exercise, and this has been handled by a committee approach in this instance. The appropriate probability functions within typical Monte Carlo simulators are reviewed, and input parameters carefully screened for the E-M field. In addition, the parametric method is applied to the hydrocarbons in place calculation and to the reserves calculation using the output from simulation runs which test critical reservoir parameters. The case study demonstrates that the parametric method is a particularly useful tool - especially for reserves evaluation when multiple simulation runs are available.
Breaking of a Paradigm: The Simultaneous Production of the Gascap and Oil Column
Authors: Billiter Travis C. , Dandona Anil K. 
Published: December 2007

Abstract
The conventional way to produce an oil reservoir that has a gascap is to produce only from the oil column while keeping the gascap in place so that it can expand to provide pressure support. Depending upon the geometry, reservoir dip angle, and oil production rates, gas can either cone down to the oil producers or breakthrough as a front, leading to substantial increases in the gas-oil ratios of the oil producers. This paper presents a unique production methodology of simultaneously producing the gascap and oil column while injecting water at the gas-oil contact to create a water barrier to separate the gascap and oil column. This methodology has application in reservoirs with a low-dip angle, relatively large gascap, and a low residual gas saturation to water. It is demonstrated that the net present value of the project is improved if there is an immediate market for gas. The work also demonstrates that the recovery from the gascap is minimally affected by heterogeneities in the reservoir. This is shown using geostatistical reservoir models. The effect of heterogeneities on oil recovery is also documented.
P. 431
Application of Forecasting and Uncertainty Methods to Production
Authors: Spencer J. Allan , Morgan David T.K. 
Published: December 2007

Abstract
Uncertainty has become an ever important subject for the oil industry as the engineer learns to use the skills of the mathematician. The use of distributions rather than single numbers, and uncertainty analysis has permeated through many common areas of the work of the oil industry.
Such methods have, for a number of years, been applied to estimate the range of reserves for discoveries. when applied to production forecasting, together with other techniques, improvements can be achieved both in the forecasts and in the understanding of the restrictions that are being placed on production. This, in turn, can lead to improved levels of production.
P. 339
Resolving Reservoir Uncertainty to Create Value
Authors: Chorn L.G. , Croft M. 
Published: December 2007

Abstract
Technology application focuses upon acquiring knowledge to reduce the uncertainty surrounding large capital investments in exploration and production. In practice, the industry makes incremental investments that exploit the increasing knowledge base for the asset, such as an exploration lease or a newly discovered field. Reservoir characterization reduces the uncertainty surrounding the development of a field by gathering and interpreting data from many interrogatory tools. The acquisition of that knowledge cannot be valued readily by traditional discounted cash flow (DCF) analysis and this has caused considerable problems for both the suppliers and users of technology. A new financial tool called Real options analysis is evolving which estimates the value of acquiring a knowledge base or developing a new technology. The value recognized by Real options reflects management's flexibility to reduce the uncertainties inherent in discovering and producing hydrocarbons.
Real options analysis is a decision and valuation approach that estimates the net present value of managing uncertainty. When the uncertainty of a financial outcome is large and the time to resolve the uncertainty is sufficiently long, the value of a real option can be large.
Mobil is extending Real options analysis to manage technology applications and optimize investment relative to resolving uncertainties. This article describes extensions made to the analysis technique for valuing a technology application. The methodology is illustrated with the application of integrated reservoir characterization techniques to reduce uncertainties in recoverable volume and well productivity. The Real options analysis indicates that a maximum value benefit in reducing reserve's uncertainty can occur at high expenditures. The maximum is a function of project's estimated NPV (with uncertainty), characterization analysis time, and the cost of delay.
P. 347
The "Well Learning System" - The Evolution of a Tool Into A Modern Management System for Drilling Operations
Authors: Minton R.C. , Vik R.B. 
Published: December 2007

Abstract
The "Well Learning System" (WLS) is a Microsoft Project adaptation formerly used to describe the processes carried out by the Drilling Engineer when planning a Drilling Operation. However, in the course of planning BP Norway's Deep Water Exploration well for the Barden prospect, the team has extended the capability and applicability of the software. It is now being used to describe, manage and report on the activities of the multi-disciplined team involved in the project; to ensure that all team members have ready access to Company polices, standards and reference manuals, and that they all have immediate access to the most up-to-date project information. It is also being used as an assurance tool, as a method of performance tracking and as a means of capturing lessons learnt throughout the planning and execution phases of the well.
In this way the tool is being used to demonstrate compliance with BPN's Drilling Management System, without the need for in depth audits, and in such a way as to be responsive to the requirements imposed by evolving organisational models.
P. 525
Optimization of Cuttings Removal by Use of Real-Time Annulus Pressure Measurements While Drilling
Authors: Pedersen B.R. , Zajaczkowski J. 
Published: December 2007

Abstract
This paper demonstrates how real-time monitoring of downhole annulus pressure can be used to reduce risks and optimize the drilling process especially in the extended reach applications. Field data shows how real-time pressure data are used interactively to optimize cuttings removal and adjusting mud weight. The ability to monitoring and subsequently controlling downhole circulating pressure enables tight acceptance windows between estimated pore pressure and fracture gradient.
P. 565
Why Guidelines?
Authors: Babson E.C. 
Published: December 2007

This paper was prepared for the 44th Annual California Regional Meeting of the Society of Petroleum Engineers of AIME, to be held in San Francisco, Calif., April 4–5, 1974. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal provided agreement to give proper credit is made.
Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.
Some time ago I was indiscreet enough to make some comments about the proposed "Guidelines" in the hearing of Sam Sarem. Once you make an error like that, it doesn't take Sam long to nail you. So I find myself up here making a speech just because of what seemed at the time to be a minor indiscretion.
My qualifications, such as they are, for participating in this discussion are largely the result of having been around longer than most anybody. I have been working in the oil industry for forty years, many of them as an employee of a large corporation. I have worked in research, engineering, operations, and management. For the past ten years, I have been a consulting engineer. As nearly as I can see, the main difference between consulting and working for a big corporation is that a consultant seems to have a lot more bosses and their patience is shorter.
In any discussion of Guidelines to Professional Employment, two questions Professional Employment, two questions are fundamental:What is the purpose of formulating Guidelines?If the purpose is a worthwhileone, do we need formal Guidelines to accomplish it?
After all, we have been getting along without formal Guidelines for a long time, and since we are all subject to plenty of rules, regulations, guidelines, etc. already, we should hesitate to establish new ones unless they are absolutely necessary. Let us not kid ourselves. In the real world, guidelines historically become rules and rules eventually become laws. If there is not some way of bringing pressure on the recalcitrant employer, why have guidelines?
First North Slope Installed Water Injection Booster using Below Grade Electrical Submersible Pump (ESP)
Authors: Williamson Jane , Laule Bob , Hefley Mike , Hazen Beez , Richards Peter 
Published: December 2007

Abstract
A water injection booster pump system using a below ground "can" Electrical Submersible Centrifugal pump (ESP) will be described. This pump, an integral part of the Milne Point Unit water injection system, is the first such installation on the North Slope of Alaska. The can ESP was chosen as a speedy, flexible, low footprint, cost effective solution to increase water injection. The pump successfully increased water injection capacity to over 20,000 bpd at 3200 psi discharge, an increase from 8000 bpd at 2600 psi As a result of the project, reservoir pressure and oil production has increased substantially in the fault blocks receiving additional water injection support. The paper will provide an overview of the project design and installation, with emphasis on downhole aspects of the pump design (geotechnical, ESP, completion).
P. 381
Estimation of Formation Properties Using Multiprobe Formation Tester in Layered Reservoirs
Authors: Badaam H. , Al-Matroushi Salem , Young N. , Ayan C. , Mihcakan M. , Kuchuk Fikri J. 
Published: December 2007

Abstract
Vertical interference tests across stylolite zones were carried out in a number of wells using the wireline multiprobe formation tester as a part of the reservoir characterization for the pilot gas injection areas in a Middle East Carbonate reservoir. For each test, the pressure and flow rate at the sink probe and pressures at the horizontal and two vertical observation probes were recorded as a function of time. For the interpretation of the pressure measurements from these tests, a detailed reservoir model was constructed based on the field geology and openhole logs, particularly resistivity images. Vertical communication across tested zones and individual layer horizontal and vertical permeabilities are obtained. High permeability zones were identified with some lateral continuity across wells. Some zones were found to be local permeability barriers with well developed stylolite zones. The results will be used in the modeling of a pilot gas injection study.
P. 479
Subsalt Imaging Using Full Tensor Gradient and 3D Seismic Data, Mississippi Canyon, Gulf of Mexico
Authors: Prutzman John M. 
Published: December 2007

Abstract
Imaging of the base of salt and subsalt prospects with 3D seismic data is difficult and time consuming. The Mississippi Canyon Area was chosen to prove the value of integrating 3D full tensor gradient data with 3D seismic to enhance the geologic model for drilling and development. The full tensor gradient data was acquired by Bell Geospace using a gradiometer originally developed to navigate the U.S. Navy trident nuclear submarines. It has very high sensitivity and is able to capture meaningful high frequency data not found in normal gravimeter data. Because all nine gravity gradient tensors are measured, the data gives information on the size, shape, and edges of the salt. The gravity and gradient responses for an initial geologic model developed from 3D seismic data were subtracted from the Bell measured data. The results were used to reinterpret the seismic data and modify the geologic model until the differences were significantly reduced. The revised model reinterpreted the pay horizons as a broad anticline lying below the salt. The gradiometry data also refined the interpretation of the edge and base of salt, lowering the base as much as 1,250 feet in some areas. The final geologic model also had significant improvements in density, particularly in the shallow layers. This study proves that 3D gradiometry data provides an important independent constraint for successfully interpreting seismic data, particularly in areas of poorly imaged seismic reflectors.
Multiphase Transportation: Hydrate Plugging Prevention Through Crude Oil Natural Surfactants
Authors: Leporcher E.M. , Peytavy J.L. , Mollier Y. , Sjoblom J. , Labes-Carrier C. 
Published: December 2007

Abstract
Multiphase transportation is more and more contemplated in the development of oil and gas fields both in conventional and frontier areas (from remote satellite fields to deep offshore). This new environment has set forward new challenges in the field of hydrate plugging prevention in subsea flowlines. Increases of transportation distances and water depths place the fluids well inside the hydrate formation domain, and hence threaten flow in multiphase export lines.
In such conditions, conventional hydrate prevention (alcohols, insulation, heating) can become very expensive and can in some cases jeopardize the economy of the project. To challenge this anticipated situation, the oil and gas industry has been looking for low dosage inhibitors: kinetic inhibitors which can delay hydrate crystallization, anti-agglomerants which let the hydrate crystallize but ensure their transportability in a slurry.
This second process creates a water-in-oil emulsion which remains a transportable suspension after crossing the hydrate equilibrium curve.
We have investigated whether this process could occur by itself with some surfactants naturally present within some crudes. Some research works have confirmed that some "natural surfactants" such as resins and asphaltenes have properties similar to synthetic surfactants.
Since 95, extensive experimental work has been done at the University of Bergen (1, 2) and Elf research center (3) on a 1" loop with different crudes and fluid blends. The hydrodynamic tests have demonstrated the capability of natural surfactants to prevent hydrate plugging. Based on these results, an experimental methodology to evaluate hydrate transportability of a given crude has been developed.
This method could reduce the need of inhibitors during the first years of production and thus result in large savings. With the present development of subsea-water separation technology, this process could further become a standalone alternative.
P. 509
In Situ Stress and Moduli: Comparison of Values Derived from Multiple Techniques
Authors: Warpinski N.R. , Peterson R.E. , Branagan P.T , Engler B.P. , Wolhart S.L. 
Published: December 2007

Abstract
This study compares the moduli and stresses obtained from dynamic measurements (e.g., logs or tomograms) and static tests (microfracture stress tests, core tri-axial compression tests) at M-Site, where there is a full suite of both types of data as well as other supporting information. The study shows that the dynamic moduli and log-derived stresses are considerably different from the measured in situ values as determined from microfracture stress tests. 2-D images of moduli and stress were also calculated from p-wave and s-wave tomograms, but the primary value of these results is in the qualitative description of the reservoir. The choice of modulus and stress values has a significant effect on processes such as hydraulic fracturing.
P. 569