bluuebunny/crossref_metadata_2025_split huggingface dataset:
Planning the First Deepwater Well Offshore Norway
Authors: Minton R. C. , Thorogood J. L. 
Published: December 2007

Summary
BP Norge was awarded acreage in the Norwegian Fifteenth Licensing Round, with water depths up to 1420 meters. Three-dimensional seismic studies revealed a number of significant structures in these licenses, and the decision was made to evaluate the most interesting of these at the earliest opportunity. As a consequence, the well engineering team proceeded to plan the first exploration well, which was to be drilled in 1275 meters of water in the Nyk High area off northern Norway.
The team faced two significant challenges. The rig market for fourth generation semisubmersible drilling units capable of drilling in these water depths was such that there were no Norwegian approved vessels available. Hence, they had to plan for the importation of an appropriate rig and introduce a new drilling contractor to the Norwegian sector. Additionally, the water depth was indicative of a dynamically positioned drilling operation, and the Norwegian authorities needed to be convinced that this unit and the associated drilling program were appropriate for the task at hand.
Consequently, there were a number of key processes that were central to the success of this exercise. These included detailed project planning, wide ranging risk assessments, and accessing the knowledge and skills of groups inside BP Exploration with experience in these operations. Visible compliance with our internal technical and Health, Safety, and Environment (HSE) systems and policies was a central feature of this project, along with compliance with the Norwegian requirements. As the first well of this nature in the Norwegian sector, these processes were all key to final approval to proceed with the drilling activity.
We describe how these aims were achieved by detailing the well engineering team project management, the risk assessment procedures that were implemented, the approach to regulatory compliance, and the verification processes that were put in place. The detailed engineering studies and the performance of the first well will be reported separately in later papers.
Gulf of Mexico Subsidence Monitoring Project With a New Formation-Compaction Monitoring Tool
Authors: de Kock A. J. , Johnson T. J. , Hagiwara Teruhiko , Zea H. A. , Santa Fernando 
Published: December 2007

Summary
Formation compaction in unconsolidated geopressured turbidite reservoirs in the Gulf of Mexico (GOM) is an issue of great uncertainty and concern. When compaction occurs, it changes the porosity and permeability properties of the reservoir rock and can affect recovery efficiency and well productivity. It can deform well tubulars, creating operational problems and shortening well life. If compaction is significant, especially when multiple stacked reservoirs are involved (as in the case in this field example), then compaction can create a subsidence bowl at the ocean floor. In GOM offshore operations, this could cause platforms to subside deeper into the water and create potentially severe safety problems; therefore, failure to properly address issues of compaction and subsequent subsidence during the design and development phases of these capital intensive, deepwater projects could lead to severe financial setbacks.
It is crucial to have a compaction monitoring program in place because of the broad impact of compaction and seafloor subsidence. As a result, we developed a new formation-compaction monitoring tool (FCMT) and new methods of measurement and interpretation. The FCMT is a wireline device that uses multiple gamma ray detectors to determine locations of and precise distance between radioactive (RA) markers planted in the formation or casing. Compaction of the formation can be measured by changes in the distance between the markers. For precise estimation of the vertical distance between a pair of markers, the new method uses an array of three or four detectors.
By examining the tool response to a marker, we developed a new method to determine the exact vertical and lateral location of the marker by using a Lorentzian response model; consequently, not only the vertical compaction but also lateral displacement of markers can be monitored with the new method.
The accuracy of the tool was established in the test facility where gamma ray sources were placed at precisely known intervals. The tools were run centralized at three logging speeds (5, 10, and 15 ft/min.), and data were collected at 0.1-in. intervals. The vertical distances between a pair of RA markers spaced 30 ft apart were measured accurately to within 0.1 in.
The first baseline logs were collected successfully in the four wells in a GOM deepwater development. High consistency among measurements from different logging passes proved that the FCMT can provide precise distance measurements with newly developed methods.
Evaluating Completion Damage in High-Rate, Gravel-Packed Wells
Authors: Burton R. C. , MacKinlay W. M. , Hodge R. M. , Landrum W. R. 
Published: December 2007

Summary
Conoco recently completed and tested a series of high-rate, gravel-packed oil wells. Analysis of the well test data for the first completion indicated that significant formation/completion damage had been caused during the gravel-packing process. Extensive laboratory testing designed to closely simulate the completion procedure was performed in conjunction with detailed completion pressure loss evaluation. The studies identified the loss control material (LCM) pill used during completion operations as the primary source of damage. A new, self-breaking, LCM composition was designed that provided fluid-loss control with minimum formation/completion damage. This LCM system and a number of other design improvements were used in the field's remaining gravel-packed completions.
We describe the analysis of well test data and the application of this information to evaluate completion procedures for these high-rate, cased-hole, gravel-packed completions. The analytical technique used is unique in that it combines laboratory, analytical, and operational data to quantify individual components of the total measured pressure drop across the completion. This approach provides significantly better insight into completion performance than merely stating an overall completion pressure drop, skin value, or well flow efficiency.
The result of this systematic analysis of pressure losses is a better understanding of formation damage effects and the factors that influence them during the completion process. This in turn allows completion procedures to be modified to target specific areas for improvement.
Experimental Investigation on the Injectivity of Phenol-Formaldehyde/Polymer Gels
Authors: Bryant S. L. , Borghi G. P. , Bartosek Martin , Lockhart T. P. 
Published: December 2007

Summary
Knowing the injectivity of a gelant (i.e., the pressure gradient required to achieve a given flow rate) enables the designer to program the rate/volume schedule of a water shutoff treatment. Bulk gelation times determined from bottle testing have been used often to estimate available pumping time, but such tests do not measure the evolution of gelant rheology as crosslinking proceeds, nor do they measure the tendency of the gelant to undergo filtration within a porous medium. These factors can affect injectivity significantly, resulting in pumping times much less than the bulk gelation time. We describe techniques for discriminating between viscosification and filtration by means of experiments in porous media, making use of multiple pore volume (PV) injection, step changes in flow rates, and in-line capillaries. Tests with phenol-formaldehyde-crosslinked polymer gelants, which possess a number of characteristics favorable to high temperature applications, show that filtration of pregel aggregates in sandpacks and cores can play the dominant role in reducing the mobility of the gelant. The filtration behavior is not universal; one gelant formulation showed no loss of mobility at all by this mechanism. When filtration does occur, it is strongly correlated to the age of the gelant (i.e., time the gelant has spent at temperature) but is relatively insensitive to the permeability of the porous medium or the presence of residual oil. The viscosity of the gelants tested evolves in similar ways in bulk and during flow in porous media.
The Effect of Stress on Permeability of Sandstone Cores
Authors: Gray Donald H. , Fatt Irving 
Published: December 2007

Introduction
The effects of mechanical stress on reservoir rock parameters are now generally accepted as beingimportantinreservoirengineeringcalculations. In several oil fields the unique behavior of the reservoir has been attributed to the influence of overburden pressure or internal fluid pressure on rock permeability or fluid content.Although the gross effects of overburden pressure on permeability, porosity, waterflood efficiency, electrical resistance and sonic velocity have now been established, there are some very interesting, and perhaps important, details of rock behavior under stress that have not heretofore been studied.In this paper we will show that permeability anistropy of several sandstones is a function of overburden pressure. We will also show that permeability reduction of cylindrical samples of two sandstones, when subjected to mechanical stress, is a function of the ratio of radial to axial stress.Most studies of overburden pressure effects made in the past have attempted to duplicate reservoir conditions by applying hydrostatic external pressure on all surfaces of the sample. Assuming perfect elasticity, that is, no viscoelastic flow during geological time, reservoir rock in situ cannot be under hydrostatic stress as is apparent from the value of 0.25 for Poisson's ratio for most rock. In the absence of tectonic forces the horizontal stress component
(1)
(2)
If there are directional permeability effects, as has been reported from field and laboratory studies, 10, 11 then one would expect hydrostatic stress as used in the laboratory to give a different permeability reduction from that occurring under reservoir stress conditions.The influence of stress on directional permeability was measured by a modification of the method first described by Maasland and Kirkham for use on soil samples. Their method permits calculation of the permeabilities along each of the three mutually perpendicular axes of a cubic sample. The modification reported in this paper extends the method to observing these permeabilities when the sample is under hydrostatic stress.The Hassler sleeve type of core holder is satisfactory for studying overburden pressure effects on permeability if a known force is applied to the end plugs. Wyble used a sleeve core holder but did not load the end plugs. In this paper we combine sleeve pressure and axial force to give permeability changes which we believe are close to those occurring in reservoirs when reservoir pressure changes. The combination of sleeve pressure and axial force assumes, however, that the sleeve pressure simulates both vertical stress and horizontal stress in one conditions.

METHOD

PERMEABILITY ANISOTROPY
The Maasland and Kirkham method of measuring permeabiHtyanisocopyusesacubeofporousmaterial which is open on three faces and has discs with a center hole for an air inlet cemented to the other three mutually perpendicular faces (Fig. 1).
SPEJ
P. 95^
Interference Analysis for Anisotropic Formations - A Case History (includes associated paper 6406 )
Authors: Ramey H.J. 
Published: December 2007

Many formations, such as channel sand, appear to exhibit simple ky-kxanisotropy. Directional permeability has an important effect onplanning fluid-injection oil recovery. The method discussed in thispaper uses data obtained during water injection to determine major andminor permeability axes and the orientation of the unknown permeability matrix.

Introduction
It has long been known that many formations appear toexhibit simple ky-kx anisotropy. This model also may beapplicable for formations containing trending fracturepatterns. Knowledge of directional permeabilityobviously would have an important effect on planningreservoir development, particularly for fluid injectionoperations. A recent study by Papadopulos outlines methods for interference analysis in anisotropic formations. Themethod is used here to analyze a field water-injection testto determine major and minor permeabilities and theorientation of the unknown permeability matrix. The method also may be extended to pressure falloff (orbuildup) interference analysis.
The theory of flow of either fluid or heat through ananisotropic medium is well established. A brief reviewof this information is sufficient here. We consider that awell is produced at a constant volumetric rate in aninfinite, anisotropic medium. The formation has aconstant thickness and porosity, and the total systemeffective compressibility is constant. Collins has presentedperhaps the best-known solution to this problem in thearea of oil production technology. In the mid-1960's, aseries of papers appeared in the groundwater hydrologyliterature dealing with the problem of well testanalysis for anisotropic aquifers. Studies by Hantush, Papadopulos, and Walton are particularly notable. ThePapadopulos study appears to be well-suited for applicationto analysis of oil and gas well test data and serves asthe basis for this study. The purpose of this paper is topresent analysis of actual field data with the Papadopulosmethod in a form readily useable by petroleum engineers.The method is extended to falloff data.

Theory
The Collins solution for the pressure field caused by awell producing from an anisotropic reservoir is correct, but it assumes the directions of the major and minorpermeability axes are known and are aligned with thewell-location coordinate system. In the general well testanalysis situation, the direction of the major permeabilityaxis would be unknown. Fig. 1 shows the known welllocation x-y coordinate system with the unknown permeability axes, X-Y, oriented at some unknown angle 0.The pressure at (x, y, t) caused by a line-source well at theorigin was presented by Papadopulos:
2 h (pi - px, y, t)kxxkyy - kxy ----------------- =141.2 q B
1- Ei .....(1)2
kxx = 1/2{(kxx+kyy) + [(kxx-kyy)2+4kxy2] 1/2}....(2)
kyy = 1/2{(kxx+kyy) − [(kxx-Kyy)2+4kxy2]1/2}.....(3)
kxx − kxx= arctan ......................(4)kxy
JPT
P. 1290^
A Method for Determining the Exponent Value in a Forchheimer-Type Flow Equation
Authors: Phipps S.C. , Khalil John N. 
Published: December 2007

This article presents a direct method for determining the exponent in a Forchheimer-type flow equation. Forchheimer proposed the following expression as the "law of flow" in porous media:
P n = au + bu, .................................(1) L
where
p/ L = pressure gradient u = volumetric velocity (flow rate per unit area) a, b = constants for a particular porous media n = velocity exponent
It is well established in oil and ground-water flow that velocities are generally sufficiently low such that Darcy's law is usually valid as the law of flow. That is,
P = cu,........................................(2) L
where c = a constant.
In those cases where Darcy's law is not valid, Muskat states that the empirical flow data can be expressed in all cases by an equation of the form of Eq. 1, with n 2 when flow velocity is sufficiently high to be in the turbulent flow region. Eq. 1 is also applicable when flow is laminar, but kinetic energy losses are large relative to viscous forces.
Although it is not the purpose of this article to discuss the range of validity of either Eqs. 1 or 2, it should be noted that the application of Eq. 1 is appropriate more often than is commonly recognized. Many high-rate Middle Eastern wells, particularly those in fractured reservoirs, are described by Eq. 1, as first reported by Baker. Using Eq. 2 in place of Eq. 1 can result in errors on the order of 50 percent or more in predicting well rates.
It is well documented in the literature that a rate equation based on Eq. 1 also applies to many gas wells. Nevertheless, the use of the empirical Rawlins-Schellhardt backpressure flow equation remains common. Cornelson has recently presented a discussion of the potential error in predicting gas rates and reserves when the Rawlins-Schellhardt equation is used in place of Eq. 1 for the flow equation.
In addition to reservoir flow considerations, well screens, perforations, and other near-wellbore effects generally cause the pressure loss to be proportional to n th power of the flow rate. Investigators in the field of ground-water hydraulics note that n may deviate significantly from 2 and should be determined separately for each well. In such cases, n is usually determined by trial-and-error curve fitting of well-test data. A direct solution for n, as well as the associated flow coefficients, is possible using the following procedure.
Run the well-flow test such that at least three pressure drawdown values are obtained for three rates at equal flow times.
P. 883
Some Aspects of Sand-Oil Fracturing in Long Heterogeneous Sand Sections
Authors: Wilson Lejeune 
Published: December 2007

Abstract
On the northwestern coast of Peru, the International Petroleum Co., Ltd., initiated sand-oil fracturing in late 1953. As of May 31, 1955, 319 jobs had been performed in 61 of the 71 producing pools and in all eight of the producing formations. The wells treated have thick producing sections completed through gun-perforated casing, perforated liners, or combination strings.
In the average treatment 300 bbl of refined oil was used to carry 18,900 lb of Ottawa sand; in most cases, the sand-oil mix was injected down the annular space. About 50 per cent of the jobs were done in wells where a thick series of sands and shales were exposed.
Of the 319 jobs done, 70 per cent (or 271 jobs) were successful; the total additional oil produced of May 31, 1955, was 1,860,633 bbl and at that time additional oil was still being produced at the rate of 5,419 BOPD. Only the six most important producing sands are discussed in the paper. In one of these (Lower Parinas sand) a comparison was made between the results of nitroshooting and sand-oil fracturing. Composite production curves and typical electrical-log sections are shown for each of the six sands. Also a statistical summary of results from all eight formations is presented.
Variables which might have affected the success of treatments were investigated empirically and theoretically, but no satisfactory means of predicting results of sand-oil fracturing was found. It was noted, however, that the beneficial effects were divided into three categories: induced fractures, elimination of well damage, and opening new reservoirs. The general conclusions were that sand-oil fracturing was successful in wells where as much as 75 per cent of the exposed formation was shale, in old, apparently depleted wells, and that opening new reservoirs plus the elimination of well damage were important factors in the successes.
Construction of Models that Simulate Oil Reservoirs
Authors: Wygal R.J. 
Published: December 2007

WYGAL, R.J., GULF RESEARCH and DEVELOPMENT CO., PITTSBURGH, PA.

Introduction
Many laboratory studies of porous media are based on experiments using test packs of sand, glass beads and other granular materials. More confidence can be had in the results of such studies if the test packs are known to have uniform properties throughout, to be mechanically stable and to be accurately reproducible. This paper presents a method by which such packs of a variety of shapes and sizes may be constructed using a particle distributor. Some factors which limit the usefulness of unconsolidated packs as a means for simulating reservoir rock are described. A method of overcoming these limitations, which involves artificial cementation of the packs, is presented.

DEVELOPMENT
Particles packed by the tamping or vibrating techniques are usually either non-uniform or mechanically unstable. An invention by Currie and Gregory overcomes these difficulties to some extent. The invention is based on the use of a stream of falling particles impinging on and passing through a distributor matrix of several layers of closely spaced spheres. The particles are well dispersed by numerous collisions with the spheres. They become homogeneously distributed at some distance below the distributor matrix and at that position are collected in the sample container. This apparatus, however, was found to be ineffective when small particles were used since small particles accumulate on the top surfaces of the spheres.
An improved distributor matrix was made, first in the form of a stack of five sieves, and then in the more adaptable form of spaced layers of wire screen. Fig. 1 shows a longitudinal view through a five-layered distributor of eight-mesh wire screen. This device gives excellent results.* Fine particles pass through the distributor with very little hold up. The fine structure of the wire matrix with its many deflecting surfaces ensures good particle distribution. There are no dead areas immediately below the screen as were sometimes observed to occur below a matrix of spheres. Using such a device, 20–30 mesh sands were packed to a porosity of 32.1 per cent at rates varying from 0.17 to 6 lb/min. The lowest porosity achieved by tamping small increments of similar sands into a container was 33 per cent.Motion pictures at 3,000 frames/sec of the surface of a growing pack of 2–3/4 nun glass beads have helped to show the mechanism by which packs of low porosity are obtained. The beads, although packed at the roe of 5 lb/min, were observed to hit the pack surface singly, for the most part, and at well spaced points of impact.
SPEJ
P. 281^
Northeast Butterly Pool - Case History
Authors: Butler Roy , McCloud S.D. , Marshall Jack 
Published: December 2007

Abstract
In producing the Northeast Butterly Pool crude oil it was necessary to pump sand consolidating agents into the formation, treat with large amounts of emulsion breaker, blend with high gravity crude, heat in the stock tanks as well as the heaters, and blend additionally as the oil entered the pipeline. Steam jets and drains installed in heaters and two trucks equipped with sand buckets, working 24 hours a day, were necessary to separate the produced sand from the oil and remove it from the area. Despite these problems, over 2,500,000 bbl of oil have been produced in less than 10 years from a reservoir covering 185 surface acres.

Introduction
The Northeast Butterly Pool, located in Garvin County, Okla., approximately 3 miles northwest of the town of Davis, is unique in several respects. It is the purpose of this paper to share the knowledge gained in combatting the many adverse conditions present in the pool. The possibility that the solutions arrived at in exploiting this reservoir might aid in the development of future pools, which would otherwise be abandoned as non-commercial, has been an added stimulus in the writing of this case history.

History of Development
The discovery well of the Northeast Butterly Pool, the W. M. Butterly No.1, was completed on Dec. 20, 1945, at a total depth of 4,422 ft and with a plugged back total depth of 4,109 ft. Producing through perforations opposite the Oil Creek sand formation, Ordovician age, the initial potential, pumping, was 240 B/D of 13° API gravity oil, with a bottom bole pressure of 2,500 psia. With one rig in use the field underwent orderly development on 10-acre spacing with five wells drilled in 1946, four in 1947, two in 1948, and one in 1949. Of the 13 wells drilled, one was a dry hole and one was plugged and abandoned during completion due to mechanical difficulties. An offset, 50 ft west of the latter, was drilled as the eleventh producing well in the pool.