bluuebunny/crossref_metadata_2025_split huggingface dataset:
Cementation Exponents in Middle Eastern Carbonate Reservoirs
Authors: Focke J. W. , Munn D. 
Published: December 2007

Summary
The cementation exponent, m, is a major factor of uncertainty in the calculation of hydrocarbon/ water saturation in heterogeneous carbonate reservoirs. Hydrocarbon saturations as high as 70 or 80%, calculated with the conventional value m = 2, may disappear completely with m values of 3 and 4 (Fig. 1), which are quite common in carbonate rocks. Laboratory data obtained in heterogeneous carbonate reservoirs often show a wide scatter (Fig. 2). Constant (average) m values are usually used in spite of such scatter, and data points with m values much higher than the average value are often rejected to obtain straight-line trends.
This paper presents the results of a study of the relationship between variable m values measured on core plugs and detailed carbonate rock types. The scatter in the data is analyzed in terms of rock type. We conclude that the high m values are often representative for specific rock types and that these values should not be rejected but applied selectively in log analysis over those intervals where these rock types occur.
Field Study of a New High-Temperature Fracturing Fluid in South Texas
Authors: Walser D. W. 
Published: December 2007

SummaryExtensive field development of a new fracturing system incorporating a temperature-delayed crosslinker was undertaken over a 15-month period in south Texas. Treatments performed at depths from 7,500 to 17,100 ft [2290 to 5210 m] revealed that the new fluid has properties superior to those of high-temperature systems that use conventional organometallic crosslinkers. Treated formations include the Wilcox, Frio, and Vicksburg.The use of this new fluid has resulted in lower and more consistent friction pressures. Average sand concentrations have been increased. A significant decline in the occurrence of screenouts has been observed.
Exact Solutions for Infinite-Conductivity Wells
Authors: Papatzacos Paul 
Published: December 2007

Summary
In pressure transient testing, the infinite-conductivity condition translates mathematically into a uniform-pressure (or uniform-potential) condition at the well. This means the flux at different points of the well should be determined in such a way that potential remains uniform at the well. The integral equation for accomplishing this is solved analytically to yield the Laplace-transformed potential. For fractured-well problems, this leads to a relatively fast algorithm for drawing type curves directly on a computer screen. For limited-flow-entry problems, the analytical pressure expression can be used with the method of images to treat problems in reservoirs of finite thickness and/or areal extent.
Fracturing and Testing Case Study of Paludal, Tight, Lenticular Gas Sands
Authors: Warpinski N. R. , Branagan P. T. , Sattler A. R. , Lorenz J. C. , Northrop D. A. , Mann R. L. , Frohne K. -H. 
Published: December 2007

Summary
This paper is a case study of the stimulation and testing of tight, lenticular sands in the paludal interval of the Mesaverde group in the Piceance basin at DOE's Multiwell Experiment (MWX) site in Colorado. Topics discussed include geologic data, stress test results, well testing, laboratory core studies, stimulation and stimulation analyses, and postfracture operations.
Regional Geology of the Delaware Basin
Authors: Cook V.O. 
Published: December 2007

Abstract
The Delaware basin of West Texas has a long, complex history and the events that occurred during this great period of time are related to the present economic conditions of West Texas. Geological history in the area presently occupied by the Permian Basin began with gentle tectonic movements and shallow seas during Cambrian and Lower Ordovician time and reached a peak of activity during late Pennsylvanian and early Wolfcampian time. Following this period of pronounced activity, the area became relatively quiet; reefing, along with associated back- and fore-reef deposits, came into prominence. In the Delaware basin vicinity, oil acid gas accumulation has been influenced by the environment of deposition of the rocks comprising the geological column and by tectonic movements that have modified sedimentary framework. Faulting and folding are the principal mechanisms for trapping hydrocarbons in the deeper fields of the basin. Shallow accumulations are often controlled by stratigraphic traps. In addition to a trap, a source of hydrocarbons and presence of rock porosity are necessary for the existence of a reservoir. Gas reservoirs in the Devonian and Ellenburger of the Delaware basin are found primarily in fracture porosity while the Wolfcampian and Pennsylvanian conglomerate reservoirs and middle Permian sand accumulations are characterized by intergranular porosity. The true source of hydrocarbons found in these fields is unknown. Possible sources include origin within the reservoir rock and migration from adjacent shale sections.
Introduction
The Delaware basin of West Texas and southeast New Mexico covers an area about 200 miles long and 100 miles wide. It is a prime example of a large sedimentary basin in which vast amounts Of rock have been deposited. As sedimentary basins in general are important to the petroleum industry of the world, so is the Delaware basin important to the industry of the West Texas-New Mexico area. This prominent geological feature can be expected to attain even greater importance in the future as the quest for oil and gas continues. The growing importance of this significant area is emphasized frequently, especially when the industry notes the ever-increasing number of deep tests announced for the basin and vicinity. The index map of regional structure (Fig. 1) shows the major features that make up the Permian Basin of the southwest United States. The Midland basin on the east and the Delaware basin on the west are separated by the Central basin platform. Both of these basins were areas of deep water during most of Permian time; because of this, they were filled with shales and sandstones deposited in a marine environment. The Central basin platform is an area of Permian reefing that grew over an older structural feature - the West Texas structural platform. South of the Central basin platform is an elongated east-west sedimentary feature called the Sheffield Channel.
JPT
P. 1260ˆ
Determination of Parameters for Individual Layers in Multilayer Reservoirs by Transient Well Tests
Authors: Gao Cheng-tai 
Published: December 2007

Summary
Approximate expressions for the pressure response and flow rates of individual layers are given when a well produces with a constant production rate from an infinite multilayer reservoir with and without interlayer crossflow. The kh product and skin factor of each layer can be determined by one drawdown test if the common wellbore pressure and the rate of each layer can be measured at the same time. The behavior of the crossflow, caused by skin factors, is discussed. A new method for determining the vertical permeabilities of the shales between layers is developed that uses the crosspoint of the two straight lines of drawdown or buildup curves. This method avoids measuring the wellbore pressures of the producing interval and the closed interval at the same time.
The Preservation of Primary Porosity Through Hydrocarbon Entrapment During Burial
Authors: O'Brien J. J. , Lerche I. 
Published: December 2007

Summary
We examine the manner in which trapped pore fluids can inhibit sediment compaction during burial and, hence, can enhance primary porosity at depth. In our model studies, we find that primary porosity can be enhanced through fluid entrapment by a factor of two to three at a depth of 30,000 ft [9144 m]. Preservation of porosity is accompanied by the development of an overpressured condition. The magnitude of these effects depends on the pore fluid, its compressibility, the depth at which the reservoir is sealed, the mechanical properties of the rock matrix, and—in the case of a gas reservoir—the thermal gradient. These results indicate that reservoir formations of significant porosity may be preserved to depths greater than 30,000 ft [9144 m] and that, under favorable conditions, it may be possible to identify such formations seismically.
Review of Operational Experience Drilling Wells Through an Underwater Manifold Center
Authors: Hodgson R. K. 
Published: December 2007

Summary
Drilling techniques required for such developments as the Shell/Esso Central Cormorant development—which is now more than halfway through its drilling and completion phase—differ substantially from normal drilling practices. These differences are reviewed, and the constraints and procedures required to ensure safe and parallel drilling/completion operations in conjunction with the Underwater Manifold Center (UMC) production are explained. Other areas of experience discussed are the weather influence on operations, deviated drilling from a semisubmersible, rig anchoring, and underwater surveillance.
Evacuation of a Residual Oil Pipeline by Inert Gas Displacement
Authors: Webb S. , Bogucz E. , Levy E. , Barrett M. , Snyder C. , Waters C. 
Published: December 2007

Summary
This paper describes an analysis developed to model the inert gas displacement process for evacuating a high-pour-point oil from a long pipeline. The governing equations were derived from the basic conservation equations for mass, momentum, and energy. The resultant computer program accounts for such effects as pipeline elevation changes, laminar and turbulent oil flow, temperature-dependent oil viscosity, and heat loss from the oil to the ground. Results of computations for an 84-mile [135-km] residual oil pipeline operated by the Pennsylvania Power and Light Co. are presented and compared with pressure measurements obtained during a trial purge of the system. Calculations show that the minimum N2 volume required for a successful pipeline evacuation increases considerably with increased delay time. In addition, theoretical results indicate that for this case, the pipeline purge operation must begin within 20 hours of a shutdown to avoid evacuation difficulties.
Prefracture and Postfracture Formation Evaluation Necessary To Characterize the Three-Dimensional Shape of a Hydraulic Fracture
Authors: Holditch S. A. , Robinson B. M. , Whitehead W. S. 
Published: December 2007

SummaryIn layered, complex, low-permeability gas reservoirs, the problem of excessive fracture-height growth and erratic fracture-growth patterns make fracture-treatment design and evaluation very difficult. In this paper, we describe the importance of collecting and analyzing data before, during, and after a hydraulic-fracture treatment so that the three-dimensional (3D) properties of both the formation and the fracture can be determined.
Mechanisms of Corrosion Inhibitors Used in Acidizing Wells
Authors: Frenier W. W. , Growcock F. B. , Lopp V. R. 
Published: December 2007

Summary
Two model compounds, n-dodecylpyridinium bromide (n-DDPB) and l-octyn-3-01, were tested in HCI acid as inhibitors for J55 oilfield steel. This paper describes the kinetic and chemical analyses conducted to arrive at inhibition mechanisms for these model compounds. These studies show that the pyridinium forms a weak bond with the chloride-covered surface and is sensitive to temperature and [HCl]. Octynol, however, chemisorbs and produces a film that contains a reaction product of the acetylenic alcohol. This film is quite insensitive to changes in temperature and [HCl]
An Improved Water-in-Oil Emulsion Mud
Authors: Brandt G.W. , Weintritt D.J. , Gray G.R. 
Published: December 2007

Abstract
A water-in-oil emulsion mud free of inert solids has been developed to provide a solution to certain problems associated with drilling, completing and servicing wells. Such invert-emulsion muds are satisfactory for use in wells with temperatures up to 300F and with pressures requiring densities up to 18 lb/gal. The emulsifier used in the preparation of these muds is the mixed salts of fatty acids. It is used in weighted muds in conjunction with a unique organophilic-clay suspending agent. The muds are prepared with ordinary mixing equipment at the wellsite. These muds have been used for drilling through the productive zone, for covering the zone to be perforated or to protect existing perforations during workover operations. Fewer difficulties in servicing wells and in getting wells back on production were experienced when these invert-emulsion muds were used as protective fluids to prevent water or mud from contacting exposed formations.

Qualifications of Invert-Emulsion Muds
An increasing number of wells are being drilled, completed and serviced with oil-base emulsion muds. These water-in-oil emulsions are commonly called "invert emulsions". The amount of water in an oil-base mud may vary from a trace to 60 per cent of the liquid volume of the mud. For purposes of this paper, the primary distinction between an invert-emulsion mud and an oil-base mud is based on whether the water is added as a definite part of the mud composition. In an invert-emulsion mud, the water phase has the important function of imparting controllable properties and characteristics to the mud. The muds described here have been found to have the most satisfactory properties when the water phase constitutes between 20 and 50 per cent of the liquid volume.
In the experimentation and development of a general purpose invert-emulsion mud, certain requirements have gradually evolved.
In the preparation of the mud:the emulsifier should be an easily handled, ground product, free of inert solids;the materials should be readily mixed with conventional rig mixing equipment in no longer time than required for mixing a water-base mud; andthe emulsifier should be effective for fresh and saline waters in a variety of crude and refined oils.
New Developments in Multiple-Well Testing
Authors: Kamal Medhat M. , Hegeman Peter S. 
Published: December 2007

Summary
Multiple-well tests provide information about reservoir characteristics such as permeability, porosity, communication between wells, and reservoir heterogeneity. A previous paper discussed the state of the art of multiple-well testing. Several developments were reported over the last few years; most are for fractured wells, double-porosity systems, and vertical permeability testing. Several field applications of multiple-well testing were also published during the last few years. This may indicate an increase in the use of multiple-well tests as a result of improvements in our ability to design and to analyze these tests. Much more remains to be done in this area of well testing. This paper discusses the new developments, summarizes the information that can be obtained from multiple-well tests with current technology, and indicates areas for future developments.
Water Imbibition and Characterization of North Sea Chalk Reservoir Surfaces
Authors: Baldwin Bernard A. 
Published: December 2007

Summary
Water imbibition of a reservoir core was dramatically affected by the removal of small amounts of tightly bound material. Both water-wet and oil-wet chalk cores contained sufficient extractable material to form multimolecular coatings over their entire surfaces. Analysis of the material removed from these reservoir cores provided some clues regarding the fluid dynamics.
Geophysical Workstations in Production Geology
Authors: Nelson H. R. , Bhattacharya G. P. , Tappmeyer D. M. , Jarzabek D. C. 
Published: December 2007

Summary
Interactive computer graphics systems have been accepted in many exploration and production operations to solve substantial geoscience problems more efficiently and accurately. Examples from several sources will be used to illustrate a few of the interactive solutions available. To illustrate these new developments, this paper introduces the basic components of the interactive environment, reviews the hardware and software system used to produce the examples, describes the interactive interpretational process, and presents the examples with a summary of the geologic problems represented.
Field Histories Show Benefits of Gas and Water-Injection Projects in Eastern Venezuela
Authors: Ramsey L.A. 
Published: December 2007

Introduction
Pressure maintenance depletion of appropriate reservoirs by fluid injection has been practiced in Eastern Venezuela since 1948. This program has resulted in benefits such as increased ultimate recovery, lowered artificial-lift costs and, in the case of gas injection, lowered treating costs and the conservation of natural gas which otherwise would be flared.
The L1 sand, OG–56 reservoir, has been under a gas-injection pressure maintenance program since 1948. The oil recovery from this reservoir as of Aug. 31, 1959 had been increased 4.75 per cent over that predicted by natural depletion. This is approximately 6.3 million bbl of additional recovery, with all present outlets still on natural-flow production. The ultimate recovery by this means of depletion is 42 per cent of the original stock-tank oil in place, or 55.9 million STB.
The G sand, 00–271 reservoir, was subjected to a pressure maintenance, water-injection program in May, 1954. As of Aug. 30, 1959, 34.5 per cent of original reserves (or 9.29 million STB of oil) had been produced. This represents an increase of 5.8 per cent, or 1.56 million bbl, over the predicted pressure-depletion recovery.

Gas Injection in L1 Sand, OG–56 Reservoir, Central Oficina Field

Reservoir Characteristics
The L1 sand, OG–56 reservoir, is a north-south trending, fork-shaped channel deposit. The south boundary is defined by the Caris fault, the flanks by sand thinning and the downdip boundary by the water-oil contact at approximately 4,480 ft subsea. The reservoir consists of two segments separated by a shale break which varies from 1 ft to several feet in thickness. The segments are in pressure communication and are considered a single reservoir.
Four of the 82 wells drilled in this sand cored the L1. Some 22 ft of L1 core was recovered and analyzed. The sand ranges from a coarse-grained, well sorted, clean sandstone with high permeabilities and porosities to medium-grained, poorly sorted, silty sandstone with clayey laminations at the top and bottom of the sand. (See Table 1.) The permeability ranges from 300 md in the dirtier sand to 8 darcies in the center portion of the cores. The weighted porosity was found to be 24 per cent.
Evaluation of Steamflood Processes With Horizontal Wells
Authors: Huang W. S. , Hight M. A. 
Published: December 2007

Summary
Steamflood operations commonly encounter steam override problems. Close well spacing is one method used to reduce this effect. Blind spot areas still exist in the pattern, however, and leave substantial amounts of unrecovered oil after project termination. This study examines the effect of horizontal wells on improving steamflood conformance. A three-dimensional (3D) numerical steamflood simulator was used. The study involves the use of horizontal wells for mature steamfloods to reduce steam override that has already occurred and for prevention of steam override if used at the start of steamflood operations. The data used are from a typical California heavy-oil reservoir.
Simulation indicates that horizontal wells can be effective for reducing or preventing steam override. For a mature 18.5-acre [7.5-ha] pattern, simulated horizontal wells increased ultimate recovery at the end of 11 years from 63.2 to 74.7% of original oil in place (OOIP). When used at the start of steamflood, a pattern of vertical and horizontal wells had a predicted recovery of 72.2% OOIP after only 7 years.
Reservoir Monitoring With the Thermal Multigate Decay Log
Authors: Wyatt D. F. , Smith H. D. 
Published: December 2007

Summary
The thermal multigate decay (TMD™) logging system, which uses a two-exponential model to isolate borehole and formation Σ effects, can be an effective device for the high-accuracy environment of monitor logging. The minimized influence of borehole parameters on the formation sigma (ΣFmCORR) results in residual oil saturation (ROS) calculations that compare favorably with expected values. The measurement of borehole parameters enables the user to determine whether proper formation flushing has been achieved and whether borehole fluid contamination of perforated intervals presents a potential interpretation problem.
Test pit data and field results indicate that the use of flushing salinities less than approximately 70,000 ppm NaCl can result in significant borehole effects to the observed formation decay rates. The necessary cross section corrections may induce systematic errors into the ROS calculations that are generally larger than any increased statistical uncertainties associated with using a smaller water salinity contrast.
Effect of Oil Composition on Minimum Miscibility Pressure—Part 1: Solubility of Hydrocarbons in Dense CO2
Authors: Silva M. K. , Orr F. M. 
Published: December 2007

Summary
This paper examines the effect of oil composition on the phase behavior of CO2/hydrocarbon mixtures and, hence, on the development of miscibility in a CO2 flood. Results of component-partitioning measurements are reported for mixtures of CO2 with five synthetic oil systems: normal alkanes, branched alkanes, naphthenes, aromatics, and a mixture of all four molecular types. The results of the experiments indicate that unsubstituted ring structures are less soluble in dense CO2 than branched or normal alkanes with the same number of carbon atoms, but that the addition of alkyl side chains to ring structures improves their solubility. Also reported are component-partitioning measurements for mixtures of CO2 with three crude oils: Rock Creek (paraffinic), Maljamar (more aromatic), and Rock Creek plus 15 wt% of a mixture of aromatic components. The experimental results suggest that of the many factors that influence extraction of hydrocarbons by dense CO2, the distribution of molecular weights present in the oil is the most important.
A New Analytic Model for Fracture-Dominated Reservoirs
Authors: Karasaki Kenzi , Long Jane C.S. , Witherspoon Paul A. 
Published: December 2007

Summary
A new analytic model for analyzing well test data from fracture-dominated reservoirs is presented. It is a concentric composite model with a finite-radius well located in the center. In the inner region the flow is assumed to be linear, and in the outer region the flow is assumed to be radial. Solutions are obtained analytically and type curves for ranges of dimensionless parameters are presented. The model can be used to find the extent and the flow parameters of the fractures near the well and the average values for the entire system provided that wellbore-storage effects do not mask the early-time data.
Faja Case Study Results on a Single Well, MFM-7S
Authors: Everett R. V. , Herron M. , Pirie G. , Schweitzer J. , Edmundson H. 
Published: December 2007

Summary
Factors expected to be of importance in understanding a deltaic environment are grain size and sorting, cementation, compaction, and diagenesis. In an attempt to isolate two of these variables, sorting and grain size, a well was selected where these parameters could be related to logging measurements.
Here, the Oficina formation is a complex series of stacked, river-derived, heavy-oil-saturated, sand-dominated sediments overlain, in turn, in the upper section by shale-dominated estuarine (brackish) sediments. We identified zones that have potential water production on primary recovery even though the oil saturation is close to 90%. Studies of lithology, mineralogy, texture, and porosity from extensive log and core data with novel interpretation methods resulted in a detailed geologic description of the reservoir.