bluuebunny/crossref_metadata_2025_split huggingface dataset:
Generalized Hydraulic Calculation Method Using Rational Polynomial Model
Authors: Pilehvari Ali , Serth Robert , Lagad Vishal 
Published: December 2007

Abstract
Abstract: Current methods of hydraulic calculations for non-Newtonian fluids encountered in the oil fields necessitate, as a first step, determination of an appropriate fluid model, e.g., Bingham plastic or yield power law. The calculated parameters of the chosen fluid model are then plugged into the corresponding set of hydraulic formulas.
In this study, a generalized hydraulic calculation technique has been developed and programmed that requires as input only the raw rheological data for the fluid and the values of the relevant hydraulic parameters. It is not necessary to incorporate in the program the many empirical models currently used to represent non-Newtonian fluid behavior and the associated logic to determine which model is appropriate for a given set of rheological data. The new hydraulic calculation technique is based on two important developments.
First, a new and powerful rheological model, called Rational Polynomial (RP), has been developed. Using a variety of data from the literature, it is shown that the rational polynomial model is capable of accurately representing the rheogram of virtually any time-independent fluid.
Second, a generalized hydraulic calculation procedure has been developed which is applicable to any time-independent non-Newtonian fluid. The Rabinowitsch-Mooney1 equation is integrated numerically utilizing the rational polynomial correlation. For laminar flow, this integration directly provides the solution for flow rate versus pressure drop. The integration also provides the parameters needed in the calculation of turbulent flow utilizing the generalized power law procedure developed by Metzner and Reed2.
The predictions of the developed method have been compared with several sets of experimental hydraulic data from different sources, gathered from large-scale flow loops.
The tested cases include laminar and turbulent flow of various drilling fluids in both pipe and annular geometry. The predictions of the rational polynomial and the generalized hydraulic calculation method are shown to be quite accurate and superior to those obtained by the currently available standard techniques.
New Testing Protocols and Regulatory Guidelines to Promote Further Development of Synthetic-Based Fluid Technology
Authors: Friedheim James E. , Candler John E. , Rabke Stephen P. 
Published: December 2007

Abstract
Since the introduction of synthetic-based mud (SBM) technology in the Gulf of Mexico, stakeholders have worked toward realization of the pollution-prevention aspects of SBM technology without losing the benefits of enhanced drilling performance. In addressing the issues of SBM in the Coastal Effluent Limitation Guidelines, the U.S. Environmental Protection Agency (EPA) recognized the pollution-prevention potential for SBM technology, but also determined that the exiting test protocols needed to be improved to measure environmental performance. In response to the Coastal Effluent Limitation Guidelines, industry work groups, including EPA scientists and engineers, took on the specific tasks of identifying and modifying test protocols that would allow continued positive development of SBM technology. The resulting test protocols for biodegradation, toxicity and analytical chemistry as described in the Effluent Limitation Guidelines for SBM technology will form the structure for usage of existing non-aqueous fluids and development of new fluids and fluid blends.
This paper details the process of protocol and regulatory development, which is a success story applicable to other regulatory arenas and other issues in the U.S. The resulting regulatory framework and technology will lead to U.S. offshore operations becoming the hot bed of pollution prevention in the global offshore drilling community. The authors will show how continued use of SBM technology in the Gulf of Mexico will allow successful development of deepwater petroleum resources in an environmentally responsible manner.
Laser Drilling: Determination of Energy Required to Remove Rock
Authors: Gahan B. C. , Parker Richard A. , Batarseh Samih , Figueroa Humberto , Reed Claude B. , Xu Zhiyue 
Published: December 2007

Abstract
Samples of sandstone, limestone, and shale were prepared for laser beam interaction with a 1.6 kW pulsed Nd:YAG laser beam to determine how the beam's size, power, repetition rate, pulse width, exposure time and energy can affect the amount of energy transferred to the rock for the purposes of spallation, melting and vaporization. The purpose of the laser rock interaction experiment was to determine the threshold parameters required to remove a maximum rock volume from the samples while minimizing energy input.
Absorption of radiant energy from the laser beam gives rise to the thermal energy transfer required for the destruction and removal of the rock matrix. Results from the tests indicate that each rock type has a set of optimal laser parameters to minimize specific energy values as observed in a set of linear track and spot tests.
In addition, it was observed that the rates of heat diffusion in rocks are easily and quickly overrun by absorbed energy transfer rates from the laser beam to the rock. As absorbed energy outpaces heat diffusion by the rock matrix, local temperatures rise to the minerals’ melting points and quickly increase SE values. The lowest specific energy values are obtained in the spalling zone just prior to the onset of melting.
Three-And Four-Phase Flow Compositional Simulations of CO2/NGL EOR
Authors: Guler Baris , Wang Peng , Delshad Mojdeh , Pope Gary A. , Sepehrnoori Kamy 
Published: December 2007

Abstract
CO2 mixed with NGL is being evaluated as a method to enhance viscous oil recovery from Schrader Bluff and other oil reservoirs at Milne Point, Alaska. The sequestration of CO2 is a secondary objective of these proposed projects. Mixtures of CO2 and NGL with the crude oil show a large three-phase liquid-liquid-gas region, so three and four-phase flow may occur in the reservoir when water is alternated with the miscible injectant. A compositional EOS simulator has been used to simulate the oil recovery for both three-phase and four-phase flow cases. The objective was to understand how important it is to simulate four-phase flow rather than use a three-phase flow approximation. Two methods were used to model three and four-phase relative permeabilities from two-phase relative permeabilities as well as to evaluate the sensitivity of the results to the relative permeability parameters. A two-dimensional vertical cross-section of the reservoir was modeled with a stochastic permeability field to approximate heterogeneities. These simulations clearly show that under these conditions, four-phase flow is significant. Four-phase flow occurs over a significant part of the reservoir and affects both the sweep efficiency and the injection and production rates when the wells are pressure constrained and the production pressure corresponds to the three-phase region of the phase diagram. The results are also very sensitive to the relative permeability parameters regardless of which relative permeability model is assumed. The project life is particularly sensitive to the relative permeability and is longer for four-phase flow than predicted by a three-phase flow approximation because the relative permeability of each phase is lower when four phases are modeled.
Evaluation of Cyclic Steam Operations at Cymric 1Y Diatomite
Authors: Ambastha A. K , Kumar M. , Skow L. A. , Evola G. M. 
Published: December 2007

Abstract
Cymric 1Y is a heavy oil diatomite reservoir in California, U.S.A. with an estimated original oil-in-place (OOIP) of 425 MMSTB. Diatomite reservoirs have low permeability (average of 5 md or less) and high porosity (50-60%).
The primary objective of this study was to investigate future development options using a consistent Base case for the cyclic operation in the 1Y pilot area. Field data from the in-fill pilot area, with a well spacing of 5/8-acre, and a fine-grid simulation of a four-well segment was used in this study.
Results show that fine grids (of the order of one ft), perpendicular to the steam-induced fracture orientation, are necessary to properly capture the effects of sharp temperature and saturation gradients in the primary fluid flow direction. Initial saturation, reservoir matrix permeability, fracture halflength, capillary pressure, and flowing bottom-hole pressure were identified as key parameters at Cymric 1Y.
Results also show that the cyclic steam development at 5/8-acre may result in 22% recovery. Infilling to 5/16-acre spacing could increase the recovery to 34% OOIP. Success of steam drive at Cymric 1Y would require that fractures remain open at both injectors and producers. A successful steam drive could further boost the ultimate recovery.
Novel Push-Pull Displacement Method to Determine Relative Permeability Hysteresis in Heavy Oil Reservoirs
Authors: Okazawa Tadahiro , Serres Anita J. , Rancier Douglas G. , Corry Kathleen E. 
Published: December 2007

Abstract
For heavy oil reservoirs it has been a very difficult task to determine relative permeability curves using reservoir fluids. In the steady-state method, saturation is quite insensitive to variation of fractional flow of phases due to the severe mobility contrast between the injected phase and the displaced phase. The Displacement method works fine for the imbibition process where high-mobility water displaces low-mobility heavy oil; however, it does not work for the drainage process where the displacement is almost piston-like, hence the information on fractional flow obtained is limited to a very narrow high oil saturation range and is not useful.
The new method consists of two test stages. First, to determine the imbibition relative permeability using the displacement method. Second, to undertake a push-pull displacement test to determine the drainage relative permeability. The first portion of the push-pull test is a repetition of the imbibition test to the point of breakthrough. Having known the imbibition relative permeability, one can determine the saturation profile in the sample core at the end of the imbibition process. At the expected breakthrough point, the flow is reversed by oil injection from the original producing end of the core. The well-distributed saturation profile at the start of the drainage process provides information on the fractional flow in a wide range of saturation. History of production of water and oil from the original injection end and pressure drop across the core determines the drainage relative permeability.
The method was applied to preserved cores from the Clear Water formation of the Cold Lake oil-sand reservoir as well as to silica-sand packs. The tests were performed using cleaned Cold-Lake bitumen and simulated formation brine at a temperature range from 100 C to 180 C which represent stages in the cyclic steam stimulation process in Cold Lake. The test results exhibited little evidence of relative permeability hysteresis.
Design of Tubing Collar Inserts for Producing Gas Wells Below Their Critical Velocity
Authors: Putra Satya A. , Christiansen Richard L. 
Published: December 2007

Abstract
Liquid production can be a serious problem in gas wells if there is inadequate energy to lift the liquid from the well bore. The liquid accumulation problem in gas wells is known as liquid load up, causing a well to die early. And it is commonly start when gas wells produce below the Turner critical velocity. This paper presents research on a new technology for liquid lifting in gas wells, so that it can produce below the critical velocity.
The liquid lifting technology that was developed is a lifting device, called inserts, that are placed in the production string of a gas well. The study for liquid lifting with inserts was done in an experimental flow loop. Various aspects of insert design were studied, such as insert opening, insert spacing, effect of liquid and gas flow rates, and performance of different types of inserts. Experimental studies in the flow loop show that inserts are able to enhance liquid lifting with two mechanisms: lifting by droplet transport, and lifting by inhibition of downward liquid fluctuation.
From the experiments on the flow loop and case studies with the gas well model with inserts, which include the mechanistic churn flow model, criteria for application of inserts in gas wells were proposed: the flow pattern should be in churn flow, the gas superficial velocity should be below the critical velocity of Turner et al., and there should be no excessive pressure drop caused by flow through inserts.
Estimating Multiphase Flow Properties Using Pressure and Flowline Water-Cut Data from Dual Packer Formation Tester Interval Tests and Openhole Array Resistivity Measurements
Authors: Zeybek M. , Ramakrishnan T. S. , Al-Otaibi S. S. , Salamy S. P. , Kuchuk F. J. 
Published: December 2007

Abstract
Multiphase flow and production cuts are affected significantly by relative permeabilities under reservoir conditions. Yet their in-situ determination is practiced only in isolated cases, and these have used array resistivity logging. Although wireline dual-packer formation-testers provide direct flow tests, analysis thus far has been confined to the determination of single-phase permeability and anisotropy. In this paper, we present a methodology to integrate the formation tester pressure and water-cut measurements with openhole array resistivity measurements to obtain relative permeabilities of oil and water.
It has been demonstrated previously that the filtrate invasion process, although uncontrolled, contains quantitative information of the fractional flow curve. The sampling process is similar; it is described by the multiphase/multi-component flow equations for which the initial condition is set by the invasion process. Geometrically, while the invasion process is largely cylindrical, the sampling process is not. To combine the two, we parameterize the invasion problem in terms of multiphase flow properties and drilling conditions, and carry out a simulation exercise, including generation of resistivity logs. The fractional flow parameters obtained, by matching the observed resistivity logs are then used for modeling fluid sampling with a formation tester. Comparison of the simulation results with the observed water-cut and pressure data allowed for further refinement of the relative permeability curves. A field example of the application of the above methodology will be discussed.
A Variable Block Size Model for the Characterization of Naturally Fractured Reservoirs
Authors: Rodríguez-N. Rafael , Cinco-L. Héber , Samaniego-V. Fernando 
Published: December 2007

Abstract
A variable block size model is presented to study naturally fractured reservoirs, taking into account continuous uniform, exponential and normal distributions of matrix block sizes. The work is based on the transient matrix flow and is an extension of the analytical model formulated by Cinco, Samaniego and Kuchuk for a finite number of block sizes. Several new groups of the pressure derivative function were developed to study the features of their graphical representation in log-log scales, to determine the matrix block size distribution corresponding to a certain shape of the curves. These groups are a better diagnostic tool than the conventional pressure derivative function, specially for pressure data on the transition period between the fracture storage dominated flow and the matrix pseudosteady-state flow. The solutions are obtained in the Laplace space, involving an integral which is numerically solved.
Nonlinear Regression: The Information Content of Pressure and Pressure-Derivative Data
Authors: Onur M. , Reynolds A. C. 
Published: December 2007

Abstract
It is shown that commonly used procedures for estimating parameters by regressing on pressure derivative data are based on incorrect covariance matrices and thus violate the underlying statistical basis for nonlinear least squares parameter estimation. Although the resulting estimates of model parameters may be reasonable, calculated confidence intervals are meaningless. Here, we show how to compute the correct derivative data covariance matrix that should be used for estimating parameters by nonlinear least squares. It is also shown that the information content of derivative data cannot be greater than the information content of pressure data in the sense that regression on derivative data with the proper covariance matrix will not yield smaller confidence intervals than those obtained by regressing on pressure data only. In fact, we prove that matching a data set including all interior derivative data plus two appropriate pressure points will yield exactly the same estimates and confidence intervals that would be obtained by regressing on pressure data only.
Theory and Analysis of Injectivity Tests on Horizontal Wells
Authors: Peres Alvaro M. M. , Reynolds Albert C. 
Published: December 2007

Abstract
This work addresses the behavior and analysis procedures for injectivity tests on horizontal wells completed in an oil-bearing reservoir. In general, pressure and pressure derivative behave quite similar to the single-phase solution calculated with oil properties, thus flow regimes can be identified by log-log plots. However, skin factor and effective well length estimates are severely affected if one neglects the effect caused by the contrast in fluid mobility. A simple approximate analytical solution for the wellbore pressure is derived in this work. The accuracy of this solution is verified by comparison of results obtained from a reservoir simulator using hybrid grids and local grid refinement. The analytical solution, supported by simulator results, indicates that the injected water going through a damaged zone has a strong and distinctive effect on both pressure and pressure derivative behavior at early times. It is also shown that, if relative permeability data are available, an equivalent single-phase data can be constructed from the measured wellbore pressures. These equivalent single-phase data can be analyzed by standard single-phase flow techniques for horizontal wells, providing reliable estimates for effective permeability, skin factor and effective wellbore length.
Trends in Reservoir Simulation: Big Models, Scalable Models? Will you Please Make up Your Mind?
Authors: Gorell Sheldon , Bassett Robert 
Published: December 2007

Abstract
Over the past 20–30 years, reservoir simulation technology has gone through various stages of acceptance and utilization. This paper will discuss the most common workflows as well as several of the emerging trends in reservoir simulation technology, particularly: 1) building ever larger increasingly complex simulation models, 2) building smaller models, which can be evaluated quickly, and 3) building scalable or "fit for purpose" models. This paper will discuss these trends in more detail, reconcile these approaches and discuss the appropriateness of each method. Potential conflicts with respect to the user profile and the differing demands imposed on development and usage of a reservoir simulation system will also be discussed relative to each of these workflows.
Technique to Integrate Production and Static Data in a Self-Consistent Way
Authors: Landa Jorge L. 
Published: December 2007

Abstract
This work presents a technique to integrate production data into the reservoir characterization workflow.
The application of the technique ensures that the construction of earth models for reservoir simulation will be geologically sound and consistent not only with all the observed static and production data, but also with the earth modeling workflow philosophy, regardless of its complexity.
The technique can be considered as an advanced reservoir simulation history matching process with a complex level of parameterization. The observed production data is applied to adjust the key parameters in the workflow used to construct the static model. The magnitude of the parameter adjustments is dependent on the uncertainty associated with the parameters.
The problem is posed as an inverse problem and it requires the computation of the sensitivity coefficients of the field responses (production data) with respect to the parameters for inversion.
This paper also introduces the concept of "static" sensitivity coefficients and explores their usefulness.
An example is presented where the parameters for inversion included variogram parameters along with the mean and variance of a reference porosity histogram. The inversion was performed by adjusting parameters in the fine scale model while the production data was computed in an upscaled model.
Application of New Viscoelastic Fluid Technology Results in Enhanced Fracture Productivity
Authors: Weaver J. , Parker M. , Slabaugh B. , Walters H. , Haley W. , Bone G. , Hensley J. , Vashler J. 
Published: December 2007

Abstract
Water-based polymers, guar, and derivatized guar have been the mainstay of fracturing fluids for many years because of their low cost and highly controllable fluid rheology. However, these materials can cause significant fracture conductivity impairment leading to poorer than expected well productivity after fracture stimulation. Considerable effort has been applied to reduce the damage caused by these fluids, including: (1) applying special purification chemical processes, (2) improving polymer breakers, (3) formulating fluids with less polymer, and (4) improving fluid recovery during well flowback after treatment. Each of these processes has incrementally improved conductivity; however, one-half or more of the native conductivity is lost to frac fluid damage derived from the use of guar-based polymers.
Recent application of no polymer, surfactant-based viscoelastic frac fluid technology has demonstrated the value of non conductivity damaging fluids by generating high well productivity with small fracture stimulation treatments. While these fluids are generally nondamaging, they are limited in applicability because of high fluid loss and their inability to generate extended fractures at a reasonable cost.
This paper presents the laboratory development and initial field testing of a new, viscoelastic fluid technology that produces highly productive fractures with low conductivity damage while providing excellent fluid-loss control and high proppant-transport properties to generate design fracture geometry. This fluid has little sensitivity to temperature and salinity, and rheology is easily controlled. The fluid system combines the best properties of polymer-based fluid technology with those of surfactant-based technology.
Multilateral Junction Connectivity Discussion and Analysis
Authors: Ohmer Herve , Brockman Mark , Gotlib Mikhail , Varatharajan Prana 
Published: December 2007

Abstract
Multilateral junction connectivity failures have been identified as a recurring risk when deploying junctions featuring casing windows in unstable formations. Connectivity has previously been described as a property defining general mechanical attributes such as resistance to formation loads of the constructed junction. When a junction experiences a connectivity problem, usually because unstable formations induce mechanical loads, solids can intrude and expected junction geometry can deteriorate.
This paper explores the main connectivity issues and redefines the functional and technical requirements. An analysis of potential solutions illustrates that casing is not a suitable structural component when a full-size window is created. Our design introduces a structural layer internal to the parent casing, composed of two main prefabricated parts that create a lateral junction. A template braces the parent bore adjacent to the window, and a lateral connector interlocks with the template in such a way that it effectively supports axial and radial mechanical loads while creating a barrier against migration of formation solids. Case histories and laboratory testing confirm the structural integrity of our simple, two-trip junction construction method.