bluuebunny/crossref_metadata_2025_split huggingface dataset:
Drillstring Considerations for Gulf of Mexico's Deepest Well
Authors: Prater Terry E. , Everage S. DeWayne , Greenip John F. , Adams Burt A. 
Published: December 2007

Summary
This paper chronicles the design analysis performed to drill the Gulf of Mexico's deepest well. With small-diameter casing cemented in the hole, slimhole drilling plans for the record depth well were generated. The short fuse project required an atypical slimhole drillstring design to select a string with ample tension/ torsion capacity, sufficient flow area for hole cleaning, and immediate availability. The final design was used in an "edge of the envelope" environment with remarkable success. This paper discusses the factors involved in drillstring selection and acceptance, actual field data, post-well results, and future applications.
Optimal Control Strategy and Experimental Investigation of Gas/Liquid Compact Separators
Authors: Wang S. , Mohan R. , Shoham O. , Marrelli J. D. , Kouba G. E. 
Published: December 2007

Summary
The deployment of the new technology of gas/liquid compact separators such as the Gas/Liquid Cylindrical Cyclone (GLCC, copyright, U. of Tulsa, 1994) often requires dedicated control systems for field applications. The control strategy implementation is crucial for process optimization and adaptation, especially when GLCCs are operated at a wide range of liquid and gas flow rates. In this study, a unique and simple control strategy, which is capable of optimizing the operating pressure and adapting to liquid and gas inflow fluctuations, has been developed. Detailed simulations and experimental investigations also have been conducted to evaluate the performance of the proposed control systems. The significant advantages of this strategy are threefold: the system can be operated at optimum separator back pressure, the system can adapt to the changes of liquid and gas flow rates, and the strategy can be easily implemented using simple PID controllers available on the market. This provides the oil and gas industry with a simple, robust compact separator control technique that has the potential for offshore and subsea applications.
Frac-Pack Completion of Gas-Storage Wells for Enhanced Deliverability
Authors: Peebles Bill , Kelley Robert , Ritter Wes , Fitzpatrick Harvey 
Published: December 2007

SummaryThis case-history paper presents the results of installing frac-pack [one-step tip screenout (TSO)1 fracture stimulation and gravelpack operations]2–5 completions in gas-storage wells in the West Clear Lake field of Harris County, Texas. With the frac-pack technique, operators have fracture-stimulated six wells (new drills and workovers) in the past 3 years as part of an overall facility upgrade. Gas is injected daily into the Frio formation (5,500 ft) of the field and withdrawn at high rates during peak demand periods. A strong waterdrive can "water-out" production at the end of peak-season gas withdrawal. The water recedes when withdrawal is ended and injection restores gas volume and pressure in the reservoir. The paper presents frac-pack installation techniques, performance comparison of conventional methods and frac packs, and completion-technique selection to achieve high production efficiency.New wells that were completed with frac packs in 1994 have yielded rates up to 100 MMcf/D each with approximately 500 psi drawdown pressure. In 1995, a well capable of producing at 25 MMcf/D with a gravel pack was recompleted with a frac pack, which increased its rate capacity to 49 MMcf/D. Because of the performance of the first three wells, three more wells were completed with frac packs in 1997. The frac-pack completion has proven superior to other sand-control methods in providing highrate deliverability in the West Clear Lake field. Frac-pack completions have, in general, provided a two-fold increase in the daily production rate.Frac-pack completions and recompletions can be applied in gas-storage wells where high production rates and sand-control measures are necessary for the life of the well.This paper provides guidelines and results associated with frac packing byDemonstrating the importance of selecting completion techniques that will provide high-efficiency production from gasstorage wells. Presenting case histories of frac-pack-stimulated gas-storagewell performance over a relatively long time period. Comparing well performance of conventionally completedand frac-pack-completed gas-storage wells producing at high rates. Providing insight into the operational aspects of frac-pack completions.
Rapid History Matching Using a Generalized Travel-Time Inversion Method
Authors: Wu Zhan , Datta-Gupta Akhil 
Published: December 2007

Summary
We propose a generalized travel-time inversion method for production data integration into reservoir models using finite-difference-based reservoir simulators. Our approach is motivated by seismic waveform imaging and is particularly well-suited for large-scale field applications because the computation cost depends only on the number of wells regardless of the number of parameters or the amount of observed data. Instead of matching the production data directly, we minimize a "travel-time shift" at each well derived by maximizing the cross-correlation between the observed and calculated production response. An optimal control method is used to compute the sensitivity of the travel time with respect to reservoir parameters. Finally, data integration is carried out via a modified Gauss-Newton method.
There are several advantages associated with the proposed travel-time inversion method. First, it is robust and computationally efficient. The travel-time misfit function is quasilinear with respect to changes in reservoir properties. As a result, the minimization proceeds rapidly even if the prior model is not close to the solution. Second, the computational cost associated with the sensitivity computation depends only on the number of wells, which can be orders of magnitude lower than the number of parameters or the amount of observed data. This offers a tremendous advantage over the commonly used gradient simulator method or the conventional adjoint methods that attempt to minimize the production data directly. Furthermore, the travel time approach also offers computational advantage during minimization of the misfit function using the Gauss-Newton algorithm. We have presented several examples to demonstrate the power, generality, and practical feasibility of our proposed approach for large-scale field applications.
Geologic and Economic Significance of the Upper Morrow Chert Conglomerate Reservoir of the Anadarko Basin
Authors: Shelby J.M. 
Published: December 2007

The Upper Morrow chert conglomerate is recognized and described for its geologic significance as a new stratigraphic unit and for its economic significance as a reservoir, which has prompted the current deep drilling activity in the Anadarko basin of Texas and Oklahoma.

Introduction
The Upper Morrow chert conglomerate is a previously unrecognized stratigraphic marker and is one of the most significant gas reservoirs in the western Anadarko basin. It continues to be the object of a widespread exploratory effort in Hemphill and Wheeler counties in Texas and in Roger Mills, Beckham, and Washita counties in Oklahoma. These counties sit astride the axis of the basin and are near the Amarillo-Wichita mountain front (Fig. 1). Drilling to depths greater than 16,000 ft (4900 m) sometimes is required to reach these elusive stratigraphic traps; therefore, knowledge of the depositional environment of these Lower Pennsylvanian Morrow chert conglomerates is necessary to reduce exploratory risk. These chert conglomerates seem to fit a fan delta model, with elongate distributary channels carrying coarse sediments into a shallow marine environment.The reservoir usually is overpressured in the deeper part of the basin and may have a reserve of 1 Bcf/ft (93 million m3/m) of effective porosity on the 640-acre (2.59-km2) drilling unit. Pay thickness may exceed 50 ft (15 m), and deliverabilities of 10 MMcf/D (283 000 m3/d) are not uncommon.Before the discovery of the Shreikey field in Roberts County, TX, in 1974, little was known about the Upper Morrow chert conglomerates except from cores on one or two wells in Hemphill and Roberts counties, TX. Since the Shreikey discovery, this zone has prompted much of the deep exploratory drilling in the basin, with successful efforts in fields such as Buffalo Wallow, Reydon, Cheyenne, Elk City, and in recent discoveries.

Regional Setting
The Anadarko basin covers an area of approximately 35,000 sq miles (90 000 km2) stretching across northwestern Oklahoma, the northeastern Texas Panhandle, southwestern Kansas, and southeastern Colorado. The Morrow chert conglomerates are confined to a relatively small area in the eastern Texas Panhandle and western Oklahoma (Fig. 2). The basin is asymmetrical with its short limb and axis adjacent and parallel to the northwest-southeast trending Amarillo-Wichita uplift. This leads to an easy subdivision into mountain front, basin axis, and shelf area.Major orogenic movements occurred in late Devonian, post-Mississippian/pre-Morrowan, and post-Morrowan/pre-Des Moinesnian time, with the latter episodes producing most of the tectonic features of the area, including uplift, folding, and erosion of the Amarillo-Wichita Mountains and frontal area. The axes of faulted anticlines trend subparallel to the major uplift.
JPT
P. 489＾
Geological and Engineering Thinking in the Gulf Coast of Texas and Louisiana - Past, Present, and Future
Authors: Halbouty Michel T. 
Published: December 2007

Introduction
To understand the present situation and the future possibilities of the Gulf Coastal province, it is important to go back to New Year's Day, 1901, and review the status of world production and the extent of the application of science to the finding of oil.
The world's annual production was about 138 million bbl. Russia was the leading oil producing nation with an annual output of 68 million bbl. Of the 58 million bbl being produced in the United States, 92 per cent, or 53 million, was from the so-called "oil region" of Ohio, West Virginia, Pennsylvania, Indiana and New York. Four million, or 6 per cent, was from California, and the remaining 1 million, or 2 per cent, was produced in Texas, solely from the Corsicana field.
Learned men, and the big-time operators of that day paid little attention to new oil possibilities of other areas. When a new field, such as that in Corsicana, was found, it disturbed the thinking of the young industry. Corsicana was not very exciting to producers because the average production per well was about that of the wells in the other fields in the country. As far as the Gulf Coast was concerned, the best brains in the business said that the area would never produce any oil whatsoever, that the unconsolidated sands underlying the Coast area could have no oil, and that the region as a whole was unworthy of testing with the drill.

The Spindletop Discovery
That was the setting on New Year's Day, 1901. Then suddenly, like the cascade of a torrential flash flood, 10 days later at 10:30 a.m. the discovery of Spindletop changed the thinking of man the world over. It completely revolutionized industrial engineering and gave birth to the liquid fuel age. This significant discovery made a revolutionary impact on the entire world. It made the United States the foremost oil producing nation overnight. It was to catapult the United States into the position of first world power, although it would take a few years and a world war to bring about the full realization of that fact.
General Heterogeneous Radial and Linear Models for Well-Test Analysis
Authors: Levitan M. M. , Crawford G. E. 
Published: December 2007

Summary
This paper presents a new analytical method for solution of the pressure transient problems for general radial and linear models with heterogeneities. In these models, the storativity and the transmissivity coefficients are considered functions of the distance from the well. The solution method is based on a special transformation of variables that reduces the problem to a diffusivity equation with constant coefficients. This equation is then solved in the Laplace transform domain, and the solution is inverted into the real-time domain by the Stehfest algorithm. The solution method allows continuous variation as well as discontinuities of the rock and fluid properties. The new solution algorithm reproduces all known exact solutions for specific variation of properties including the multi-composite radial and linear model solutions.
Simultaneous Gravel Packing and Filter-Cake Cleanup With Shunt Tubes in Openhole Completions: A Case History From the Gulf of Mexico
Authors: Godwin Keith , Gadiyar Bala , Riordan Hal 
Published: December 2007

Summary
A case history from the Gulf of Mexico is presented in this paper for drilling and completing a horizontal openhole well with simultaneous gravel-packing and filter-cake cleanup with shunt tube screens. The openhole section was 277 ft, deviated from 85 to 90°. The producing sand was normally pressured. The drill-in fluid and gravel-pack carrier/filter-cake removal fluid selection was based upon extensive laboratory testing consisting of cleanup, compatibility, and sand-suspension-capability tests. A reservoir drill-in fluid comprising brine, starch, biopolymer, and sized calcium carbonate was chosen for the project. A viscoelastic surfactant (VES) fluid in a chelating agent solution (CAS) containing an enzyme breaker to simultaneously attack both the starch and CaCO3 components of the filter cake was identified as the best carrier fluid for the gravel pack. Laboratory test results, field procedures, and production results are discussed in detail, along with the decision process that resulted in the selected drilling and completion plan.
Coiled-Tubing Failure Statistics Used To Develop CT Performance Indicators
Authors: van Adrichem Willem P. , Aslak Larsen Henrik 
Published: December 2007

Summary
Coiled-tubing (CT) failures have not disappeared with a greater understanding of low-cycle fatigue in the industry. A comprehensive process to systematically analyze CT field failures has been in place since 1995. This paper describes the systematic failure-analysis process and the resulting CT failure database, which now includes more than 360 CT failures. The information reported here covers from 1995 to 2001 during a major service company's global CT operations.
The failure analysis delivers two types of statistics—the mode of failure during the event (failure mechanism) and the cause that led to it (failure cause). The failure trends for both mechanism and cause are discussed.
The CT volume used during these operations, in combination with the accumulated failures, allows for the introduction and discussion of CT performance indicators (CTPIs) that can be considered representative for the industry.
Oil/Water Separation by Induced-Air Flotation
Authors: Sylvester Nicholas D. , Byeseda John J. 
Published: December 2007

Abstract
The separation of oil, stabilized with an oil-soluble petroleum sulfonate, from brine solutions by induced-air flotation was studied in a continuous-flow pilot unit. The effects of inlet oil concentration, vessel residence time, air flow rate, bubble diameter, oil drop diameter, temperature, NaCl concentration, and cationic polyelectrolyte concentration were investigated. Oil drop and air bubble diameters, liquid residence time, and concentration of cationic polyelectrolyte were the most significant variables affecting overall flotation performance. Only drops larger than 2μm showed significant removal, while smaller drops were generated by the air-inducing rotor. The cationic polyelectrolyte improved flotation performance by increasing the number of large oil drops.
The removal rate for each oil drop size was first order with respect to oil drop concentration, and an experimental procedure permitting determination of the first-order rate constants for removal only due to bubble/drop interactions was developed. The oil drop and air bubble diameters were the only variables which affected these rate constants. Inceasing oil drop diameter and decreasing bubble diameter increased the rate constants. Comparison of the experimental and theoretically predicted rate constants showed that the mechanism of oil-droplet removal by bubbles from 0.2- to 0.7-mm is one of hydrodynamic capture in the wake behind the rising bubbles.
Perforating Unconsolidated Sands: An Experimental and Theoretical Investigation
Authors: Walton Ian C. , Atwood David C. , Halleck Phillip M. , Bianco Luis C. B. 
Published: December 2007

Summary
This paper describes the experiments and modeling undertaken to develop a perforating strategy for unconsolidated sand formations. The experimental program consists of single-shot perforations in cylindrical samples of three sizes (4-, 7-, and 10.5-in. diameters) of unconsolidated sand saturated with kerosene at residual brine saturation and placed under a high effective stress in a pressure vessel. The amount of sand produced during perforating, as well as that produced during post-shot flow, is measured, and a video probe is used to observe post-shot sand production. Computerized tomography (CT) scan equipment is used to map the geometry of the cavity. The sand features behind the casing are examined and interpreted, providing essential insights into the interaction of the charge with the sand sample. A theoretical model of the failure mode of unconsolidated sands has been developed that supports the observations.
The main results so far from this study are as follows.
Perforating does not generate a tunnel in unconsolidated sands. The intense pressures set up by shaped-charge penetration in the weak sand sample fluidize it and cause the initial tunnel to collapse. Production flow creates a dilated zone around the tunnel entrance. At a critical flow rate, a large volume of sand is produced and the sample collapses. This occurs when flowing out of a hole in an unperforated sample as well.
The implications of these results for future work and for field applications are also addressed here.
Mankind's Stake in Middle East Oil
Authors: Jennings B. Brewster 
Published: December 2007

To set the stage for discussing Middle East oil, let us review a few of the more important aspects of the world petroleum picture.
The Free World, outside the Iron Curtain, produced and used nearly 16 million B/D of petroleum last year. More than half of it, 57 per cent to be exact, was consumed in the United States. Free Europe used about a third as much as we did, or about a sixth of the total.
Big as oil consumption is today, it will soon be much larger. How big, how soon, is difficult to say because no reputable oil economist has ever yet made a long-range forecast of oil demand that was as high as consumption subsequently proved to be. There are a few straws in the wind which can be pointed out, however. Over the past five years demand in the United States has grown at the rate of about 5 per cent a year. In Europe during the same period demand has risen 12 per cent annually. Increases in oil use have been still faster in less developed countries. Last year's oil consumption in the Free World as a whole was double what it was only nine or 10 years ago. Whether such rates of growth continue, accelerate, or even slow down a little, it seems reasonable to expect that sometime between 1965 and 1975 if not sooner the Free World will need twice as much oil as it is using today.

Sources of More Oil
Where are we going to get it? Last year's oil production came primarily from the United States. Production in the United States, while less than our consumption, came to 48 per cent of the Free World's total. The Middle East supplied 23 per cent and Venezuela 17. Can we count on a continuance of supply in those proportions from those sources?
A look at the rates at which the various producing countries are drawing on their oil "bank accounts" may help us answer that question. United States petroleum production last year amounted to 8.1 per cent of our domestic proved reserves, and Venezuelan production was 6.8 per cent of its reserves. But Middle East production was only 1.3 per cent of Middle East reserves.
Obviously, the principal Western Hemisphere sources of oil the United States and Venezuela are being drawn on five to seven times as fast as those of the Middle East.
The United States, with roughly 20 per cent of the world's reserves, produces nearly 50 per cent of the world's oil output and consumes nearly 60 per cent. Overlooking the possibilities of getting oil from shale or tar sands, the facts suggest that if present trends persist, the Western Hemisphere will run out of oil before the Eastern Hemisphere does. This statement concerns only proved oil reserves. How about the chances of finding more oil?
Analyses of an Elmworth Hydraulic Fracture in Alberta
Authors: Wyman R.E. , Holditch S.A. , Randolph P.L. 
Published: December 2007

Summary
A tight gas sand with 1-µd permeability was produced, after a large hydraulic foam fracture, at rates close to predicted values. The rates of about 300 Mcf/D (8495m3/d) after 23 days would not bear the cost of development at 1979 Canadian prices. However, it is estimated that, with higher netbacks and longer fractures, commercial development would be feasible.

Introduction
The Elmworth gas field is located within the Deep basin near Grande Prairie, Alberta (Fig. 1). The Deep basin covers about 26,000 sq miles and appears to contain an enormous amount of gas in different-quality rocks. Masters1 has estimated the Deep basin could contain more than 400 Tcf of gas, recoverable at various levels of price and technology.
Canadian Hunter visualizes the gas distribution in the Deep basin as a resource triangle. In such a distribution, the sands and conglomerates of highest porosity and permeability are at the very top of the triangle. As reservoir quality decreases, the resource triangle indicates larger and larger quantities of gas in lower-porosity and lower-permeability rocks. Near the bottom of the triangle are sands approaching 7% porosity and 1 µd in-situ permeability. Within these lower porosity rocks (7 to 11%) resides a huge ultimate potential. Detailed analyses were made of logs, cores, and tests of about 20 zones from 57 wells in a 60-township area around the Elmworth field. This study indicated that, with sufficient but reasonable economic incentives, it would be possible to recover more than 200 Tcf from the lower-quality rocks within the Deep basin.2
To obtain more information on the technology and economics required to recover this gas, Canadian Hunter performed a large hydraulic fracture over the Cretaceous Falher Zones A and B in the Canhunter Texcan Elmworth Well 11–12–71–13W6. This paper presents a description and analysis of the fracture.

Petrophysical Properties
The Falher Zones A and B were cored completely, and a full suite of openhole logs was run. This suite included the induction-electrical, acoustic with variable density display, compensated neutron-density, and microlog. Selected logs and the core analysis (made at atmospheric conditions) are shown in Fig. 2. Although the entire cross section of 164 ft is considered gas-bearing, less than one-half of the section is estimated to be net pay, based on analysis of logs, cores, and pressure buildups. Sixty-six feet of this section have measured core porosities equal to or above 7%; this is shown by the shaded area on the porosity curve in Fig. 2. Permeabilities above 0.1 md also are shaded. Sonic log and pressure buildup analysis indicate a net pay closer to 45 ft. The relation between fractional core porosities (f) measured at 200 psi and sonic travel time (?t) in µs/ft is described byf=0.0054?t-0.2865.