bluuebunny/crossref_metadata_2025_split huggingface dataset:
Application of Kinetic Inhibitors to Gas Hydrate Problems
Authors: Notz P. K. , Bumgardner S. B. , Schaneman B. D. , Todd J. L. 
Published: December 2007

Summary
Laboratory and field tests since 1991 have shown the feasibility of replacing the classical inhibitors (methanol and ethylene glycol) with kinetic inhibitors. Although the kinetic inhibitors have limitations, they have been shown to be effective in preventing the formation of hydrate plugs in field situations. In many cases, there is an economic advantage to using the kinetic inhibitors. An analysis of the conditions in the production facilities must be done to ascertain the applicability of a kinetic inhibitor. The data and tests that are required to determine the applicability of a kinetic inhibitor are discussed. The application of kinetic inhibitors to flowlines in producing fields is presented.
The cost to the petroleum industry to inhibit the formation of gas hydrates is greatly increasing with the development of offshore reservoirs. Gas hydrates are likely to form in subsea flowlines unless the water is removed down to the lowest dew point encountered, highly effective insulation is used, or inhibitors are used. The first two possibilities are generally prohibitively expensive or the technology for subsea application does not exist. In many cases, kinetic inhibitors offer lower cost alternatives to classical inhibitors and are more environmentally friendly.
The results show that kinetic inhibitors can be applied economically to field-production systems. This is an area where there is very little published information at this time. In addition, the data (both field and laboratory) that are required to verify the effectiveness of a kinetic inhibitor are illustrated.
This information will help producers with hydrate problems evaluate the use of kinetic inhibitors. Savings in the range of 50% of the chemical costs and reduced downtime can be realized in many cases.
Performance of a Longitudinally Fractured Horizontal Well
Authors: Valkó P. , Economides M. J. 
Published: December 2007

Abstract
This work is an attempt to effectively unify two of the most common modern techniques for improved and accelerated petroleum production: horizontal wells and hydraulic fracturing. Greatly dependent on the in-situ stress anisotropy, hydraulic fractures are invariably vertical with a well-defined azimuth. Horizontal wells drilled along the minimum stress would accept transverse hydraulic fractures. This configuration, with multiple treatments, has been already expounded upon in the literature and is appropriate for low-permeability formations. Higher-permeability formations, the range of which has been expanded greatly with the emergence of frac&pack treatments, favor the drilling of horizontal wells along the maximum stress, resulting in a longitudinal hydraulic fracture configuration. The purpose of this paper is to provide a means to estimate the productivity index of such well completion, to compare it with that of a fractured vertical well, and to allow for sound production engineering decisions based on anticipated well performance.
Evaluation and Selection of Drill-ln-Fluid Candidates To Minimize Formation Damage
Authors: Hodge R. M. , Augustine B. G. , Burton R. C. , Sanders W. W. , Stomp Donna Atkinson 
Published: December 2007

Summary
Conoco drilled and completed a horizontal well in a depleted, high-permeability oil reservoir. The formation is an unconsolidated, clean sandstone with absolute permeability over 3,300 md. The unconsolidated nature of the formation combined with its low pressure and high permeability caused concerns regarding hole stability, fracturing, excessive fluid loss, and differential sticking. To identify the best drill-in fluid (DIF) for the horizontal section, the evaluation of fluid candidates focused on both drilling properties and formation/completion-damage potential. The testing compared fluid performance in standard drilling-fluid tests, low-shear rheology at elevated temperature, dynamic fluid-loss behavior at elevated temperature, and core-flow tests. The flow testing was performed with cores from an offset well to simulate damage caused by DIF exposure and to evaluate remedial treatment options. Also, a new laboratory-scale procedure was developed to observe the tendency of prepacked screens to be plugged by DIF filter cake and unconsoli-dated formation sand.
In addition to the laboratory testing, a review of the drilling and completion operations is presented, including performance of the drilling fluid at high overbalance pressure ( ≈ 2,600 psi) and the design and execution of subsequent remedial treatments. The production history is discussed and related to laboratory observations regarding cleanup and remedial-treatment effectiveness.
Long-Zone Squeeze Gravel Packs in Geopressured Reservoirs in the Gulf of Mexico
Authors: Bruner S. D. , Lau H. C. , Morgenthaler L. N. , Bernardi L. A. , Kielty J. M. 
Published: December 2007

Summary
Laboratory studies were conducted to determine the completion techniques for two wells in the Gulf of Mexico with well angles of 35 to 45°, completion intervals of about 400 ft, bottomhole temperatures of 222°F, and requiring a completion brine with density up to 17.0 lbm/gal. Three critical issues—fluid-loss control, pregravel-pack acid stimulation, and internal gravel packing—were studied.
Laboratory studies showed that an activated hydroxyethyl-cellulose (HEC) pill could be designed to control the fluid loss for more than 30 hours, even at a bottomhole temperature of 222°R In addition, a high-rate acid stimulation could be employed to ensure that as many perforations as possible were open to accept gravel-pack sand. Physical model studies also showed that a high-rate squeeze waterpack provided the required effective perforation and annular packing for the target wells despite the long completion interval.
These techniques were successfully implemented. Initial production data suggest that both wells, still under choke, are producing at expected rates, with low downhole drawdown.
Development and Field Trial of Two Environmentally Safe Water-Based Fluids Used Sequentially to Free Stuck Pipe
Authors: Fisk J. V. , Wood R. R. , Kirsner Jeff 
Published: December 2007

Summary
Diesel-based spotting fluids have historically been used to free differentially stuck pipe. Increasing environmental regulatory pressures have prompted the development of environmentally acceptable water-based spotting fluids. In spite of their widespread application, these new fluids have had only sporadic success in freeing differentially-stuck pipe in the field.
An extensive laboratory research project was initiated to identify potential chemistries that could offer increased performance and maintain environmental acceptability. Literature reviews revealed that previous spotting fluid research had focused mainly on the spotting fluid providing lubrication between the drillpipe and mud filter cakes. Laboratory data also revealed that the best preforming conventional spotting fluids were highly toxic to mysid shrimp.
In accordance with the new findings, a two phase spot was developed. A field application is detailed that validated the concept of the two phase spot and its method of application.
Advanced Torque-and-Drag Considerations in Extended-Reach Wells.
Authors: Payne M. L. , Abbassian Fereidoun 
Published: December 2007

SummaryExcessive torque and drag can be critical limitations in extended-reach drilling (ERD). This paper details issues related to torque-and-drag prediction, monitoring, and management in ERD wells. Results are presented from sensitivity analyses of extreme ERD trajectories such as 7- to 8-km departures at 1600 m true vertical depth (TVD). Several such wells have now been successfully drilled at the Wytch Farm oilfield using results from these studies. In such high-angle ERD wells, compression generated in the drillpipe during tripping and sliding operations can exceed the critical buckling load and cause the drillpipe to buckle. As a result, buckling initiation and post-buckling analyses are used to quantify the extent and severity of buckling and the associated increases in drag forces and pipe stresses. The paper addresses the importance of drilling data in calibrating torque/drag models to capture the continual changes in drilling parameters and operating conditions. The paper presents a number of field case studies where analyses have been conducted to directly assist drilling operations. This paper should be of high interest to engineers executing, planning, or evaluating ERD operations.
Enhanced Waterflooding Design With Dilute Surfactant Concentrations for North Sea Conditions
Authors: Michels A. M. , Djojosoeparto R. S. , Haas Henk , Mattern R. B. , van der Weg P. B. , Schulte W. M. 
Published: December 2007

Summary
Efficient selection procedures for surfactants have been applied to design a low-concentration surfactant-flooding process for North Sea oilfield application. Anionic surfactants of the propoxy ethoxy glyceryl sulfonate type can be used at 0.1 wt% concentrations together with sacrificial agents and without a polymer drive. Currently estimated unit technical costs (UTC's)—at 8% — for application in the North Sea oil fields range from $81 to $94/incremental m3, without taking uncertainty factors into account. Including such factors would likely add another $31/m3 to the costs.
A Critical Review of the Use of Pseudorelative Permeabilities for Upscaling
Authors: Barker John W. , Thibeau Sylvain 
Published: December 2007

SummaryThe properties and limitations of different dynamic pseudorelative permeability methods are summarized. Severe difficulties common to all methods are discussed: choosing the number and locations of the coarse-grid rock types, defining the simulations from which the pseudos are generated, and the dependence of the pseudos on well rates and positions. It is concluded that, in practice, pseudos cannot be used reliably to scale up from a "fine-grid" geological model to a "coarse-grid" fluid-flow model except for cases where capillary or gravity equilibrium can be assumed at the coarse-gridblock scale. Scaling up from the core scale to the geological model is more likely to be possible because capillary forces are more important at smaller scales. A practical approach to the dynamic upscaling problem is outlined, but one should not expect that the effects of the detail in the geological model will be captured more than qualitatively.
Neutron Logs Improve Interpretation of Foamed Cement, Even in Concentric Casing
Authors: Harness P. E. , Frank W. E. 
Published: December 2007

Summary
A new method of foamed cement evaluation using a comparison of open-hole and cased-hole neutron logs is described to complement existing techniques using acoustic cement evaluation logs. Together, it is possible to identify neat cement, foamed cement, fluid, and air behind pipe. Favorable results are achieved in a case study, whether the annulus is bounded by formation or a larger casing string.
Kuparuk Large-Scale Enhanced Oil Recovery Project
Authors: Hoolahan S. P. , McDuffie G. S. , Peck D. G. , Hallam R. J. 
Published: December 2007

Summary
The Kuparuk River oil field has had a "miscible" water-alternating-gas (MWAG) enhanced-oil-recovery (EOR) pilot in place since 1988. This original pilot was implemented on two drillsites previously on waterflood. The pilot was expanded to a third drillsite in 1993 to test the MWAG process in an area previously flooded by an "immiscible" water-alternating-gas (IWAG) recovery technique. Large-scale application of MWAG at Kuparuk is in progress, with a project that will more than triple current MWAG injection. Full implementation is slated for mid-1996. When completed, the Kuparuk large-scale EOR (LSEOR) project will be among the largest of its kind in the world. This paper covers the basic aspects of moving the EOR process at Kuparuk from pilot to large-scale application. A number of hurdles had to be overcome, including scaleup of field and simulation results in a consistent manner and the need to use existing infrastructure to ensure economic viability
Prudhoe Bay Gas/Oil Relative Permeability
Authors: Jerauld G. R. 
Published: December 2007

Summary
Prudhoe Bay is a mixed-wet reservoir where about half the oil recovery is attributable to gravity drainage. Gas/oil relative permeability data show that gravity-drainage recovery efficiency is poorer for more fine-grained sandstone and increases as the grain size increases. Gravity-drainage efficiency also increases with connate-water saturation. Dependence of recovery efficiency on grain size is related to changes in sorting. An effective grain size, defined by inverting the Carman-Kozeny relation, provides a useful parameter for correlating recovery efficiency. This estimate correlates well with visual estimates and direct measurements on disaggregated core. Grain size is also found to be a more effective parameter for correlating trapped gas than porosity, a common alternative. Lithology impacts trapped-gas level with finer-grained, more poorly sorted rock having higher trapped gas. Trapped gas decreases with increasing microporosity. Because little gas is trapped in microporosity, a zero-slope generalization of the Land curve better represents trapped-gas data.
Integrating Multiphase Production History in Stochastic Reservoir Characterization
Authors: Vasco D. W. , Datta-Gupta Akhil 
Published: December 2007

Summary
This paper focuses on integrating field-production history into reservoir characterization through stochastic inverse modeling. A key element of our approach is a three-dimensional (3D) streamline simulator that is orders of magnitude faster than traditional numerical simulators and thus allows for rapid inversion of multiphase production data. Stochastic permeability fields, conditioned to field-production history, are then generated with simulated annealing. We also explore the spatial resolution associated with estimates of reservoir permeability variations derived by use of field-production history. On the basis of techniques from geophysical inverse theory, we address such issues as data sensitivity, spatial resolution, averaging kernels, and uncertainties associated with our estimates of reservoir permeability. The proposed inversion technique has been applied to synthetic as well as field cases. The synthetic example involves a sensitivity analysis of multiphase production history in heterogeneous five-spot and nine-spot patterns. The field example consists of production history from a five-spot pattern in the north Robertson unit, a low-permeability carbonate reservoir in West Texas. Watercut history at the producers are used to estimate permeability variations in a two-layer (matrix-fracture) model of the reservoir. All computations were performed on a 125 MHz Pentium with an average run time of about 4 wall-clock hours, indicating the feasibility of our approach.
Influence of Water on Estimation of Gas in Place
Authors: de Hemptinne J-C. , Zhou Honggang , Moracchini Gérard , Brunella Isabelle 
Published: December 2007

Summary
The usual method for determining the gas in place (GIP) in a reservoir uses a balance equation based on laboratory measurements of the raw gas volumetric factor as a function of pressure on a water-free basis. In the reservoir, however, the gas is saturated with water. Volumetric measurements at high temperatures and pressures have been performed on a North Sea fluid at 374°F, both in water-free conditions and in the presence of an excess water. The water content of the gas at 650 bar has been determined to be 3.5 mol% (3.6 mole of water/100 mole of reservoir fluid) water-saturated reservoir fluid. A corresponding volume increase of 3.2 % has been detected. These experimental measurements have been correlated with a Tait-type equation. The S0reide and Whitson1 model has been used to calculate the water content of the gas. A modified balance equation is proposed for prediction of the GIP.
Determination of Three-Phase Relative Permeabilities From Displacement Experiments
Authors: Nordtvedt J. E. , Ebeltoft Einar , Iversen J. E. , Sylte André , Urkedal Hege , Vatne K. O. , Watson A. T. 
Published: December 2007

Summary
We describe and demonstrate a method for the determination of three-phase relative permeability functions at reservoir conditions. Two- and three-phase displacement experiments are conducted on a low-permeability chalk sample, and estimates of the three-phase relative permeability and capillary pressure functions are obtained. We also calculate three-phase relative permeabilities with the Stone predictive model, and we evaluate them by simulating the experimental data.
A New Method To Calculate Effective Permeability of Gridblocks Used in the Simulation of Naturally Fractured Reservoirs
Authors: Lough Michael F. , Lee Seong H. , Kamath Jairam 
Published: December 2007

Summary
Current simulation technology for naturally fractured reservoirs is based on either the continuum or the discrete-fracture approach. The more commonly used continuum model can simulate complex recovery mechanisms. However, it uses a very simplified representation of the fracture system for calculating effective fracture permeability. The discrete-fracture flow method can handle complex fracture geometry. However, its use has been typically limited to basic flow calculations through a connected fracture system embedded in zero-matrix-permeability rock.
We have developed a new technique for estimating the effective permeability of gridblocks used in conventional simulators. The idea behind this technique is to integrate the realism of fracture systems, as captured by discrete-fracture models, with the complexity of the flow calculations offered by continuum models. The end product of developing this technique is an efficient numerical code based on the boundary-element method. This code permits the fracture system to be complex and poorly connected, and it also includes the contribution from flow through the matrix rock. For fluid flow in the matrix rock, the fractures are treated as planar-source distributions. Periodic boundary conditions, for the flow properties, are used for the calculation of the effective permeability of individual gridblocks.
We first use a simple fracture system to demonstrate the validity of our method and to evaluate the sensitivity of the results to matrix and fracture properties. We then use fracture statistics data from the Mesaverde sandstone, effective permeability values from our code, and a continuum simulator to calculate tracer-flow patterns for a more realistic system.
Models for Heat Transfer from a Buried Pipe
Authors: Archer Rosalind A. , O'Sullivan Michael J. 
Published: December 2007

Summary
Analytical solutions are presented for the temperature distribution along a buried pipe. Two different geometries are used to model the surrounding material, and isothermal and convective boundary conditions at the pipe wall are considered. Firstly an ‘effective cylinder’ model in which the burial medium is modelled as a homogeneous annular layer around the pipe is considered and secondly a ‘half-space’ model in which the pipe is modelled as a cylinder in an infinite half-space is used. The effective cylinder configuration is of importance because it is often used in more complex computational heat transfer models. In both models coupled differential equations representing conservation of energy in the pipe and its surroundings are solved. By comparing the solution for the effective cylinder model to that for the physically more realistic half-space model, the most suitable radius of the annular layer of material in the effective cylinder model can be calculated. For a deeply buried pipe the effective cylinder radius tends to twice the burial depth of the pipe. This work also gives a calculation of the effective conductivity of the burial medium when two different materials are used, such as is the case when a pipe is placed in a trench and covered in backfill material.
Field Evaluation of a Multiphase Meter in Well-Testing Operation
Authors: Shen J. J. S. , Riley R. C. 
Published: December 2007

SummaryThis paper describes the evaluation results on the measurement accuracy and long-term operation of a multiphase meter used for well testing. The test was conducted by Chevron at its Lost Hills field in California. After many years of development work, several multiphase meter manufacturers have begun to offer their meters commercially for production operation. In this paper, commercial multiphase meters are first briefly reviewed based on the methods that those meters use to handle the fluid flow. The multiphase meter selected for this application was manufactured by Accuflow Inc. It uses the compact separation approach in handling the oil/gas/water flowstream by first separating the gas from the liquid stream and then measuring the gas and oil/water separately. The Accuflow system was installed at a gauge station in January 1996. It was designed to test wells that have productions ranging approximately from 100 to 400 bbl of fluid per day, with a high water cut (40 to 90%), and up to 200 Mcf/D of gas. For accuracy testing, the multiphase meter was piped in series with a test separator at the gauge station. Production from selected wells, covering a wide range of flow rates, water cuts, and gas volume fractions, flowed through the multiphase meter first and then through the test separator, which enabled comparison of the new meter's performance and accuracy with an existing reference. Additional tests also were conducted to compare results with a test tank at the site. The paper also discusses other operational aspects of the multiphase meter such as equipment maintenance and sand accumulation. Overall, satisfactory performance of this multiphase meter was observed, and additional units have been installed at the Lost Hills field.
Mapping Steam and Water Flow in Petroleum Reservoirs
Authors: Wilt Michael , Schenkel Clifford , Daley Tom , Peterson John , Majer Ernest , Murer A. S. , Johnston R. M. , Klonsky Louis 
Published: December 2007

Summary
During the past 5 years, we have applied high-resolution geophysical methods [crosswell seismic and electromagnetics (EM) and passive seismic] to map and characterize petroleum reservoirs in the San Joaquin Valley and to monitor changes during secondary-recovery operations. The two techniques provide complementary information. Seismic data reveal the reservoir structure, whereas EM measurements are more sensitive to the pore-fluid distribution. Seismic surveys at the South Belridge field were used to map fracture generation and monitor formation changes caused by the onset of steamflooding. Early results show possible sensitivity to changes in gas saturation caused by the steamflooding. Crosswell EM surveys were applied at a shallow pilot at Lost Hills for reservoir characterization and steamflood monitoring. Images made from baseline data clearly show the distribution of the target oil sands; repeated surveys during the steamflood allowed us to identify the boundaries of the steam chest and to predict breakthrough accurately. Applications of the EM techniques in steel-cased wells are at an early stage, but preliminary results at Lost Hills show sensitivity to formation resistivity in a waterflood pilot.