bluuebunny/crossref_metadata_2025_split huggingface dataset:
What Causes Bumps in Minifrac Pressure Declines?
Authors: Shaoul Josef R. , Pater C. J. (Hans) de , Roodhart Leo P. , Meijers Hans C. 
Published: December 2007

Summary
In many cases, a momentary increase is observed in wellhead pressure after pumping a minifrac, which could compromise reliable interpretation of the pressure decline. We found that the cause of the pressure bump was severe underdisplacement of crosslinked gel. The crosslinked gel at the bottom of the wellbore may create a plug, which effectively makes the wellbore a closed vessel disconnected from the fracture.
To avoid this bump, it is recommended to displace the crosslinked gel to the perforations or even slightly overdisplace. If this is impossible, the simplest correction for the pressure bump is to use the initial pressure decline before the bump, and shift the final decline after the bump downwards by the magnitude of the bump.
Progress Towards Zero-Based Hookup
Authors: Hume Ian 
Published: December 2007

Summary
This paper charts the step change continuous improvements achieved in U.K. completion system (CS) hookups from 1992 through 1998. Fig. 1 shows that improvements to this process have caused the man-hours/tonne required to hook up and commission (HUC) large offshore installations (greater than 20,000-tonne top-sides) to fall from an industry average of 75 man-hours/tonne to less than 10 man-hours/tonne.
The change process has been complex. It was necessary not only to challenge technical sacred cows but also philosophical, cultural, and organizational core beliefs prevalent in our industry during this period.
The story is not complete yet. There are still significant activity level reductions to be delivered, some of which have been targeted already. We have no doubt that we or others will deliver yet more.
A New Multiband Generation of NMR Logging Tools
Authors: Prammer M. G. , Bouton J. , Drack E. D. , Miller M. N. , Chandler R. N. 
Published: December 2007

Summary
This paper describes the hardware and operation of a new generation of nuclear magnetic resonance (NMR) logging tools. In the past, NMR required the logging engineer to consider the T1 relaxation times of the reservoir fluids likely to be encountered. Actual, or simply assumed, long T1's translated into slow logging speeds. The new tool generation overcomes this limitation. The key feature is that nine sensitive volumes are polarized in parallel and are read out in rapid sequence. A new sonde design speeds up the polarization process by a factor of 2. Each volume contributes equally to the result and can support identical measurements for rapid stacking and fast logging, and each can be used for individual, simultaneous measurements.
Laboratory data and field-test results are presented to demonstrate both the relative simplicity of operation and the improvement in data quality. Logging speeds typically can be upgraded by a factor of 4, while data for total porosity determination and fluid typing are acquired in a single logging pass.
Experiments and Modeling of High-Velocity Pressure Loss in Sandstone Fractures
Authors: Skjetne Erik , Kløv Trygve , Gudmundsson J. S. 
Published: December 2007

Summary
High-velocity pressure loss in Bentheimer sandstone fractures of varying fracture widths was studied. Direct measurements of the roughness showed that the fractures are self-affine. The new results support a rough fracture high-velocity pressure-loss model. The high-velocity pressure loss was described by a Forchheimer equation with a dominating square term. The square term is a power law in fracture width, and the power is given by a roughness exponent. For low velocities, the pressure loss was not described by the Forchheimer equation. In agreement with theory, a weak-inertia-flow regime exists that separates the Darcy-flow regime from the Forchheimer-flow regime. An expression for the incremental high-velocity skin of a pinched-out hydraulic fracture was derived. Asymptotically for small fracture widths the skin is a power law in fracture width.
The Benefit of Local Saturation Measurements in Relative Permeability Estimation From Centrifuge Experiments
Authors: App J. F. , Mohanty K. K. 
Published: December 2007

SummaryThe standard method for estimating relative permeabilities from centrifuge experiments is to match the production data. This study examines under what conditions local saturation measurements (in addition to production data) can improve the estimation of wetting-and nonwetting-phase relative permeabilities. Synthetic experimental data were obtained through simulation. Three distinct sets of wetting- and nonwetting-phase relative permeability curves at low and high mobility ratios were used to construct the experimental data. The relative permeabilities were then history matched through nonlinear regression using either local saturation and production measurements or only production measurements. Local saturation in conjunction with production measurements can improve the estimation of relative permeabilities from centrifuge experiments. The most significant improvement is in the prediction of the wetting-phase relative permeability at low mobility ratios (e.g., less than 5). For gas/oil systems (with high mobility ratio), the wetting-phase (oil) relative permeability was accurately estimated in all cases using an initial guess based on Hagoort's method with or without local saturation data. Prediction of the nonwetting-phase relative permeability is still difficult under some conditions.
Determination of Original Gas in Place in Ballycotton, Offshore Ireland
Authors: Chu Wei-Chun , Fleming C. H. , Carroll K. M. 
Published: December 2007

SummaryEarly, accurate determination of original gas in place (OGIP) is highly desirable for planning the future of a gas field. This paper presents a case history of an offshore gas field, using a recently developed pressure-rate-time analysis technique to illustrate the effectiveness of the method. In addition, this paper demonstrates the great benefit of permanently installed pressure gauges in obtaining consistent pressure and flow-rate data for the effective use of the technique for subsea completed wells.
Experimental Modeling of the SAGD Process - Enhancing SAGD Performance with Periodic Stimulation of the Horizontal Producer
Authors: Sasaki K. , Akibayashi S. , Yazawa N. , Doan Q. T. , Ali S. M. Farouq 
Published: December 2007

Summary
Experiments on initial stages of the steam-assisted gravity drainage (SAGD) process were carried out, using two-dimensional (2D) scaled reservoir models, to investigate production process and performance. Expansion of the initial steam chamber, its shape and area, and its temperature distributions were visualized with video and thermal-video pictures. The relationship between isotherms and steam-chamber interface was investigated to study the drainage mechanism. Temperature at the expanding steam-chamber interface was observed to remain nearly constant at close to 80°C. The effect of vertical spacing between the two horizontal wells on oil recovery was also investigated. For the Conventional SAGD case, oil production rate increased with increasing vertical spacing between the wells; however, the lead time for the gravity drainage to initiate oil production became longer. The results suggest that vertical spacing between the wells can be used as a governing factor to evaluate production rate and lead time in the initial stage of the SAGD process. Based on these experimental results, the SAGD process was modified; the lower production well was intermittently stimulated by steam injection, in conjunction with continuous steam injection in the upper horizontal injector. With the modified process (named SAGD-ISSLW), the time to generate near-breakthrough conditions between two wells was shortened, and oil production was enhanced at the rising chamber stage compared with that of the Conventional SAGD process.
A New Methodology for the Optimization of the Placement of Downhole Production-Monitoring Sensors
Authors: Nœvdal G. , Vefring E. , Berg A. , Mannseth T. , Nordtvedt J. E. 
Published: December 2007

SummaryA new methodology for designing the placement of production-well-monitoring sensors is presented. With a well-flow simulator, we estimate the inflow profile of a production well and solve the inverse problem associated with the mathematical model for fluid flow in the well. The accuracy in the estimated inflow profiles using different types and placements of sensors can be computed, and an efficient way to search for an instrumentation layout is presented.
Particle Transport Through Perforations
Authors: Gruesbeck C. , Collins R. E. 
Published: December 2007

Abstract
This paper describes a new procedure for determining particle-transport efficiency through perforations. Transport efficiency is the mass fraction of particles that are transported through the perforations relative to the total mass of particles injected. Our conclusions are based on laboratory studies of the transport of solid particles carried through perforations by different fluids having a wide range of physical properties. Prediction of particle-transport efficiencies based on theoretical considerations described in this paper gives an accurate representation of experimental results.
Near-Wellbore Halo Effect Resulting From Tip-Screenout Fracturing: Direct Measurement and Implication for Sand Control
Authors: Upchurch Eric R. 
Published: December 2007

Summary
The near-wellbore geometries of four fracture stimulations are evaluated to determine if fracturing soft, unconsolidated formations can result in placing proppant in a concentric halo around the casing, in addition to placing proppant in the fracture. Whether or not the "halo" exists impacts whether or not fracture stimulating is a viable means of sand control in unconsolidated formations.
This paper presents the findings of an investigation to determine whether a near-wellbore halo is generated during the process of fracture stimulating a well in a soft, unconsolidated formation. The investigation delves into whether net-pressure generation has any effect on the halo's formation and, finally, whether the halo could be used by petroleum operators as an inexpensive way to control formation sand production.
Results from four fracture stimulations in perfectly vertical wells are the primary data used in this investigation. In each case, all necessary steps were taken to ensure that collected data would show conclusively whether or not the halo occurred and, more qualitatively, to what extent a significant net-pressure increase resulting from a tip screenout (TSO) affected the halo's formation. All data presented here resulted from direct downhole measurements, either by bottomhole pressure gauges or by specialized azimuthal gamma ray (GR) logging tools that can directionally measure GR intensity.
To date, the possible existence and benefit of the halo has been a topic of conjecture. This study represents the first attempt at directly confirming the existence and extent of the halo under actual downhole conditions.
Digital Computer Programming for Automatic Analysis of Well Logs
Authors: Southwick S.H. , Adair T.W. 
Published: December 2007

Introduction
Improvements in well-logging tools and the introduction of new ones, together with the development of improved interpretive techniques, have greatly increased the utility of logs during the last 10 years. Instead of serving primarily for the correlation of strata, logs are now used to indicate porosity and fluid content of subsurface formations. Under favorable conditions, oil and gas saturation in subsurface reservoirs may be calculated with reliability from log data.
One log interpretation method which gives useful results from many logging programs is the resistivity index method. In this method, a resistivity ratio is computed for each porous zone of interest penetrated by a well. The higher the ratio, or index, for a particular zone in the well, the higher is the probability the zone contains oil or gas. Experience gained with the RI method has shown that selection of zones to be analyzed should not be limited to those likely to contain oil or gas. Zones thought to contain only water should also be selected for analysis. In fact, to obtain the maximum, most reliable information, a resistivity index should be computed for every porous zone in a well. Unfortunately, many hours of concentrated effort by an experienced interpreter may be required to compute resistivity indices in one well which contains numerous porous zones. Hence, it has been impractical to make calculations for all porous zones in all wells. The speed and flexibility of digital computers offer a solution to the problems of computing every porous zone and making rapid use of all available logging data. Freed from the tedium of repetitious computation, the geologist or engineer could function most efficiently by working with the computer results, combining his experience with results from computer calculations to arrive at decisions. To develop a system for analysis of well logs with a digital computer, three steps are necessary. First, the log information must be in computer language; that is, digital form. Second, computer programs must be perfected for the interpretive methods applicable to the various logging systems so that the computer completes the sequence of operations without interruption. Finally, the computer results must be tested or confirmed by comparison with manual interpretation. Step 1, the digitization of log data, both in the laboratory and at the well site, is being investigated by several companies. One machine has been developed to read and digitize logs from ordinary paper prints by a completely automatic procedure. At the present time, however, the only commercial digitization of log data is from ordinary paper prints by semi-automatic processes. Several companies offer this type of service; the charge is in the range of $0.005/datum point, or about $25/1,000 ft. (five curves on a foot-by-foot basis). With advances in technology and an increase in demand, it is hoped that this cost can be reduced substantially.
JPT
P. 35ˆ
Advances in Tightly Coupled Reservoir/ Wellbore/Surface-Network Simulation
Authors: Zapata V. J. , Brummett W. M. , Osborne M. E. , Van Nispen D. J. 
Published: December 2007

Summary
One of the most perplexing and difficult challenges in the industry is deciding how to develop a new oil or gas field. It is necessary to estimate recoverable reserves, design the most efficient exploitation strategy, decide where and when to drill wells and install surface facilities, and predict the rate of production. This requires a clear understanding of energy distribution and fluid movements throughout the entire system, under any given operational scenario or market-demand situation.
Even after a reservoir-development plan is selected, there are many possible facility designs, each with different investment and operating costs. An important, but not always considered, fact is that each facility scheme could result in different future production rates owing to various types, sizes, and configurations of fluid-flow facilities.
Selecting the best design for the asset requires the most accurate production forecasts possible over the forecast life cycle. No other single technology has the ability to provide this insight, as well as tightly coupled reservoir and facility simulation, because it combines all pertinent geological and engineering data into a single, comprehensive, dynamic model of the entire oilfield flow system. An integrated oilfield simulation system accounts for all dynamic flow effects and provides a test environment for quickly and accurately comparing alternative designs.
This paper provides a brief background of this technology and gives a review of a major development project where it is currently being applied. Finally, we describe some recent significant advances in the technology that make it more stable, accurate, and rigorous.
Application of Heat for Recovery of Oil: Field Test Results and Possibility of Profitable Operation
Authors: Walter H. 
Published: December 2007

Introduction
Many have studied and experimented with the application of heat to oil sands in an effort to recover oil generally considered to be unrecoverable by conventional means. This interest is understandable because reduction of the viscosity of the oil or, better still, complete evaporation by application of heat seems to be promising and comparatively easy to achieve.
The Worthington Corp., interested chiefly in secondary oil recovery equipment, and the Forest Oil Corp., a pioneer in secondary oil recovery methods, conducted a field test with heat injection and in situ combustion from Sept., 1953, until Aug. 1955. It was established that over 80 per cent of the oil in place could be recovered within that time. The tests were terminated when the oil production rate had fallen off to approximately 40 per cent of its maximum.
In this paper methods and means will be described concerning how this result was achieved and what conclusions may be drawn from the pilot test data with respect to the economy of large scale operations.

History of the Pilot Test, Preliminary Phase
The test site chosen was Parker pool, near Casey, Ill. This reservoir showed poor primary production and a water drive test there covering an area of 17.5 acres was considered unsuccessful. Only 23,000 bbl were recovered in five years from this area. The conditions found in the Pennsylvania sand formation are presented in Table 1.
These conditions are typical of many smaller Mid-western pools, although this oil sand is exceptionally shallow. This shallowness was considered an advantage for a first test of this kind. The pressure to be applied was low and so were the development costs. Also, in case of troubles with the injection and production wells, corrective measures would have been less costly.
A power and heat producing pilot unit suitable for the above listed conditions was built early in 1952 and shipped to the test site, where tests began on Sept. 1, 1953. This equipment has been described previously. It produced a combustion gas-air-steam mixture at maximum pressure of 500 psi, at a maximum temperature of 1,000°F, at a maximum rate of 25 tons per day. Pressure, temperature, and product quantity could be varied in wide range. Also, the composition of the gas-steam mixture could be varied from 100 per cent stir with 23 per cent oxygen by weight to a combustion gets steam mixture containing 53.4 per cent steam, 41.0 per cent nitrogen, 6.6 per cent carbon dioxide, and practically no oxygen.
Review of WAG Field Experience
Authors: Christensen J. R. , Stenby E. H. , Skauge A. 
Published: December 2007

SummaryIn recent years there has been an increasing interest in water-alternating-gas (WAG) processes, both miscible and immiscible. WAG injection is an oil recovery method initially aimed to improve sweep efficiency during gas injection. In some recent applications produced hydrocarbon gas has been reinjected in water-injection wells with the aim of improving oil recovery and pressure maintenance. Oil recovery by WAG injection has been attributed to contact of unswept zones, especially recovery of attic or cellar oil by exploiting the segregation of gas to the top or the accumulating of water toward the bottom. Because the residual oil after gasflooding is normally lower than the residual oil after waterflooding, and three-phase zones may obtain lower remaining oil saturation, WAG injection has the potential for increased microscopic displacement efficiency. Thus, WAG injection can lead to improved oil recovery by combining better mobility control and contacting unswept zones, and by leading to improved microscopic displacement.This study is a review of the WAG field experience as it is found in the literature today,1–108 from the first reported WAG injection in 1957 in Canada to the new experience from the North Sea. About 60 fields have been reviewed. Both onshore and offshore projects have been included, as well as WAG injections with hydrocarbon or nonhydrocarbon gases. Well spacing is very different from onshore projects, where fine patterns often are applied, to offshore projects, where well spacing is in the order of 1000 m.For the fields reviewed, a common trend for the successful injections is an increased oil recovery in the range of 5 to 10% of the oil initially in place (OIIP). Very few field trials have been reported as unsuccessful, but operational problems are often noted. Though the injectivity and production problems are generally not detrimental for the WAG process, special attention has been given to breakthrough of injected phases (water or gas). Improved oil recovery by WAG injection is discussed as influenced by rock type, injection strategy, miscible/immiscible gas, and well spacing.
A Review of Bubblepoint Pressure and Oil Formation Volume Factor Correlations
Authors: Al-Shammasi A. A. 
Published: December 2007

SummaryThis paper evaluates published correlations and neural-network models for bubblepoint pressure (pb) and oil formation volume factor (Bo) for their accuracy and flexibility in representing hydrocarbon mixtures from different locations worldwide. The study presents a new, improved correlation for pb based on global data. It also presents new neural-network models and compares their performances to numerical correlations.The evaluation examines the performance of correlations with their original published coefficients and with new coefficients calculated based on global data, data from specific geographical locations, and data for a limited oil-gravity range. The evaluation of each coefficient class includes geographical and oil-gravity grouping analysis. The results show that the classification of correlation models as most accurate for a specific geographical area is not valid for use with these two fluid properties. Statistical and trend performance analysis shows that some published correlations violate the physical behavior of hydrocarbon fluid properties. Published neural-network models need more details to be reproduced. New developed models perform better but suffer from stability and trend problems.
Implementing Convection in a Reservoir Simulator: A Key Feature in Adequately Modeling the Exploitation of the Cantarell Complex
Authors: Monceau E. , Delamaide E. , Sabathier J. C. , Jullian S. , Kalaydjian F. , DeGuevara J. E. Ladron , Bujanos J. L. Sanchez , Rodriguez F. D. 
Published: December 2007

Summary
As with some thick and highly fractured Iranian fields, the Cantarell complex located offshore Mexico presents features [decreases in the production gas/oil ratio (GOR) and bubblepoint pressure with time] that reveal the effect of convection.
This effect on the past homogenization of fluid properties is discussed and supported by a thorough characterization of the thermodynamic properties of actual reservoir fluids.
To model convection, the reservoir simulator used for this study was purpose adapted. Sensitivity runs were performed to demonstrate the necessity of accounting for convection when matching the past history of the Akal field, which is part of the Cantarell complex.