bluuebunny/crossref_metadata_2025_split huggingface dataset:
Modeling the Geochemistry of Scale Formation and Formation Damage in Carbonate and Sulfate-Bearing Clastic Reservoirs
Authors: Dunn T. L. , MacGowan D. B. , Surdam R. C. 
Published: December 2007

ABSTRACT
Chemical divide pathway models have been shown to be useful for delineating the evolution of formation waters and the rock-water interactions of reservoir systems. The physical and chemical processes which formation fluids undergo during production can be modeled by pathway methodology. Since these processes may result in scale formation and formation damage they are of interest to production engineers and geologists. We have developed a pathway of critical divides for the processes involved in the formation of scale minerals accompanying production from sulfate mineral bearing clastic reservoirs.
The critical divides characterizing these processes involve the following: 1) the presence or absence of sulfate bearing minerals within the production fluid contacted volume; 2) the presence of sulfur-rich petroleum; 3) the presence of iron within the formation and production line; 4) the ratio of the concentration of bicarbonate to hydrogen sulfide; 5) the mixing or dilution of the formation waters; 6) the introduction of sulfate-reducing bacteria and 7) the magnitude of pressure and temperature reduction during production. The model qualitatively predicts the liklihood of: sulfate, sulfide and carbonate mineral precipitation and dissolution within the production tubing or the formation. The prediction is based upon the pathway of interactions between production fluids and the reservoir material as well as the insitu geochemical conditions.
This pathway model has been developed from the production histories for Weber sandstone fields and has been applied to anticipated scale problems within the Tensleep and Minnelusa Formations of Wyoming during CO2 treatments. The model indicates that problems of scale formation will potentially be the greatest in the Minnelusa and that scale formation and formation damage due to CO2 injection in the Tensleep will be minimal.
Implications of Recent Laboratory Experimental Results for Hydraulic Fractures
Authors: Johnson Edward , Cleary Michael P. 
Published: December 2007

Summary
Extensive laboratory experiments on hydraulic fracturing have been performed with a convenient and proven apparatus, developed over the past ten years at MTT. Results of these experiments are presented, for instance: Dimensions of created hydraulic fractures with various injected fluids and flow ratesPressure measurements along the fracture lengthPressure responses to injection of various fluid sequences (e.g. viscosity and flow-rate variation)
These measurements generally confirm a variety of elastic models developed by Cleary in the early 1980s, which have since been widely adopted by the industry. However, we have had to greatly modify such models over the past five years, because the predictions of such purely elastic models do not seem to agree with most field measurements (e.g. with net pressure), suggesting that most existing industry models are inadequate for practical applications. The reason for such discrepancies between lab and field behavior is traced to nonlinear rock response in the near-tip region of the fracture, which we generally call the leading edge.
Other implications of these results for field applications are discussed, in particular with regard to the following primary issues: The role of fracture propagation in shut-in analysisThe role of fluid rheology in fracture openingThe importance of near-wellbore tortuosity in interpretation of pressure responses measured in the fieldThe role of stress barriers in providing only partial containment of height growth
It is suggested that current industry concepts need major revision on these and other issues (see related paper, Ref. [1]).
Characterization of Low-Permeability Dry Gas Reservoirs in the Arkoma Basin
Authors: Chen S. , Robbins R. E. 
Published: December 2007

ABSTRACT
The exploration and development strategy can be strengthened with improved understanding of reservoir characteristics. For this purpose, the characteristics of low-permeability gas reservoirs in the Arkoma basin are examined in this paper by analyzing 75 wells in a seven county area. The study area covers portions of Crawford, Franklin, Logan, and Sebastian Counties in Arkansas, as well as, Latimer, Leflore and Haskell Counties in Oklahoma. The examined reservoir characteristics included a geological background, reservoir fluid and rock properties, formation evaluation, and production performance.
Of the three types of reservoirs classified in this paper, i.e. (I) relatively high porosity/high permeability, (II) relatively low porosity/low permea-bility, and (III) relatively high poro-sity/low permeability, Type III reservoirs are the most difficult to characterize because of a dual porosity system in the sand-stone matrix. The matrix pore system is primarily composed of varying amounts of intergranular and dissolution porosities. How to characterize this type of reservoir is the main effort of this paper.
Geologic Influences on the Location and Production of Antrim Shale Gas, Michigan Basin
Authors: Manger K. C. , Oliver S. J. P. , Curtis J. B. , Scheper R. J. 
Published: December 2007

ABSTRACT
The Michigan basin's Antrim Shale is one of the most actively drilled gas plays in the United States. Last year, Otsego County, the focus of current drilling activity, was among the leaders in gas well completions.
The Antrim is a geologically complex target. Gas producing horizons, located in the black shale facies, are primarily the result of a combination of high kerogen contents and permeability enhancing fracture systems. Preliminary depositional environment and facies work is being incorporated into a depositional model which will assist in the identification of possible areas with greater organic matter preservation. Structural mapping has located subsurface geological variations likely to influence the development of fracture systems. Combined, these geologic factors suggest where gas generation and storage, and permeability are sufficiently enhanced to create economic completion targets.
All Antrim wells require stimulation treatments. Stimulation design and success, in part, is affected by the Antrim stratigraphy. Mineralogie and lithologie differences between the black shales and the gray shales that bound them appear to influence the response of the Antrim to hydraulic fracturing. Correlation of core analyses to geophysical logs will enable better location of target horizons and better control in the design of well completions.
The Antrim appears to be geologically complex in the study area and this complexity has significant influence on gas productivity. This paper presents initial results from a geologic evaluation in a four township area of southeastern Otsego County, the center of present activity. The purpose of this study is to use geologic factors to better define the location and production of gas from the Antrim Shale. Incorporation of these results in designing exploration and exploitation strategies could enhance gas production.
Modeling the Effects of Time, Temperature, and Shear on the Hydration of Natural Guar Gels
Authors: Stromberg J. L. , Brown D. , Curtice R. J. 
Published: December 2007

ABSTRACT
Laboratory work has been performed and a mathematical model formulated to describe the time, temperature, and shear effects on hydrating gels produced from natural guar-based concentrated liquid gelling agents. This same model has been applied to field scale fracturing equipment and allows the prediction of viscosity development at any point in the system. This mathematical model can be a valuable tool to equipment and job designers. The model allows the designer to determine the most feasible means of producing a desired viscosity by predicting the combined effects of time, temperature, and shear on hydrating gel.
Horizontal Well Performance in a Layered Carbonate Reservoir
Authors: Pieters D. A. , Al-Khalifa A. J. 
Published: December 2007

ABSTRACT
A heterogeneous carbonate reservoir displaying a characteristic sequence of high permeability layers above low permeability layers and undergoing peripheral waterflooding, a non-uniform flood front usually develops. Oil in the tight facies is normally trapped or bypassed when water preferentially sweeps the upper clean facies. Recovery of this bypassed oil is often complicated by the presence of overlying water. With the advent of horizontal well technology, the question arises as to whether or not this new technique can improve the recovery from these heterogeneous reservoirs.
This paper examines the use of a horizontal well and compares the result to that of a vertical well in the type of reservoir described above. A 3-0 simulation model was constructed of a localized area within the reservoir. Vertical and horizontal wells were simulated in separate cases of decreasing vertical permeability between the permeable and the tight zones. Model runs were also made with varying layer locations for the horizontal well.
Results indicated that horizontal wells in the tight facies recovered no more oil from the dirty than a vertical well penetrating the entire reservoir thickness. Furthermore, the horizontal well in the tight facies recovered the same percentage of permeable to tight as a horizontal well completed in the clean facies. The only difference being the earlier, higher recovery from the respective layer in which the horizontal well is completed. This behavior is explained by the fact that severe cross flow from permeable to tight existed. This cross flow persisted down to vertical permeability values of .0001 millidarcy.
Effects of Drying on Absolute and Relative Permeabilities of Low-Permeability Gas Sands
Authors: Morrow N. R. , Cather M. E. , Buckley J. S. , Dandge V. 
Published: December 2007

ABSTRACT
Water adsoiption/desorption (sorption) isotherms, surface-area measurements, and electron and optical microscopy all demonstrate the presence of significant microporosity in low permeability gas sands as exemplified by cores taken during the course of the Multiwell Field Experiment (MWX). Pore space in these sandstones occurs primarily as solution pores that are often partially filled by fine-structured clay minerals such as illite and smectite. Quantitative information on pore size and volume of microporosity can be obtained from sorption isotherms. A hygroscopic index for rocks based on desorption behavior is proposed. To delineate changes in pore structure that can arise during drying, water desorption isotherms, absolute permeabilities to brine, and effective permeabilities to gas were compared for preserved (undried) and dried cores. Permeabilities of cores which had been allowed to dry tended to be higher than those of the fresh cores. Changes in effective permeabilities and sorption isotherms were consistent with observed decreases in absolute permeabilities. Low water content in preserved MWX cores demonstrated that the technique used to protect them from drying was sometimes inadequate.
Slimhole Continuous Coring and Drilling in Tertiary Sediments
Authors: Randolph S. B. , Jourdan A. P. 
Published: December 2007

Abstract
A Soft Rock Project was conducted by Amoco Production Company and Elf Aquitaine on the Texas Gulf Coast in June and July 1990. The purpose of the project was to demonstrate and gain experience in slim hole continuous coring and drilling in soft sediment formations. Four wells were completed, which included two planned sidetracks. A total of 1670 ft was continuously cored and 1018 ft was full hole drilled. Both 4-3/8 in. and 3-1/16 in. hole sizes were cored/ drilled.
Slim hole continuous coring and drilling were suc-cessfully conducted in recent age sediments (Tertiary). It was determined that the most, important factor affecting wellbore stability was keeping the flow regime in laminar flow. Lost circulation in unconsolidated sands was controlled by using calcium carbonate and starch for fluid loss control. Modified face-discharge core bits used with a split tube core barrel assembly were the most effective in recovering core. Setting cement plugs and sidetracking were accomplished and open hole logs were successfully run in the slim holes.
Real-Time Formation Analysis Can Help Drilling Decisions
Authors: Allen D. F. , Sheppard M. C. , Rasmus J. C. , Ahmed U. 
Published: December 2007

ABSTRACT
During drilling it is important for the driller to know the properties of the formation being penetrated. Mud weight, the necessity for wiper trips and gas sand detection are some of the routine drilling operations that depend on the type of rock being drilled. To properly perform these operations, an analysis of the formation lithology on a real-time basis can be very important. Recent developments is MWD technology coupled with sophisticated computer processing at the rig site now provide unprecedented real time analysis of the formation being drilled. This formation analysis greatly facilitates decisions about safe mud weights, correlation and marker identification, and safe and efficient drilling. Also, the formation analysis can allow the geologist to perform a preliminary evaluation in order to plan the wireline logging program.
The term "formation analysis" as it is used here includes properties commonly estimated by oilfield geologists and petrophysicists. In addition to distinctions based on rock type (sandstone, shale, anhydrite…) and mineralogical composition, it incorporates porosity and fluid saturations since these properties influence drilling operations and are essential to computations of pore pressure.
In this paper we present the process of formation analysis while drilling. Starting at bit depth the mechanical measurements of downhole weight and torque provide an indica-tion of lithology and early warning of possible pore pressure changes. The interpretation is refined as subsequent measurements of spectral gamma ray, resistivity, neutron porosity, bulk density and Pe become available as drilling proceeds and the various MWD subs pass a particular horizon.
The interpretation of lithology is performed in a number of ways depending on which data are available at a particular depth. At bit depth the mechanical data allow distinction between major lithology types. Once the gamma ray and resistivity measurements are available a volumetric analysis is possible which provides information about sand and clay volumes as well as porosity. This volumetric analysis can subsequently incorporate the full suite of measurements. Combining gamma ray, neutron porosity and density also enables classification of lithology by reference to a prebuilt data base of lithologies. This analysis can be further refined by the inclusion of cuttings data. The analysis of lithology is extended to provide qualitative detection and description of thin beds through the supplemental use of curve shape analysis. Porosity and fluid types axe evaluated using a standard log analysis method. In this way an increasingly refined specification of formation properties becomes available as drilling progresses.
We will describe the identification of different lithologies, including the identification of thin beds, the identification of hazardous gas sands and the estimation of pore pressure in real time, which enables us to substantially reduce the risk of kicks and differential sticking.
Intelligent Control of Drilling Systems
Authors: Rowsell P. J. , Waller M. D. 
Published: December 2007

Abstract
Research in drilling automation, at the University of Nottingham, has the ultimate objective of achieving computerised drill control through the the application of an intelligent based system.
From a laboratory drill rig, various parameters are measured and stored to a database for a variety of rock types and drilling conditions. The database is used by the Inteldrill system to generate a series of Self Learning Prediction Matrices [S.L.M.P.] which allow the determination of the best drilling performance likely to be achieved. The control can be based on either maximum penetration rate or minimum cost drilling.
Minimum cost drilling is based on a cost equation which is configured with constants for the various cost centres. The computer passes drilling conditions from the drilling S.L.P.M. through the cost equation to generate a cost matrix. This matrix is then searched to determine the most economical drilling parameters. The system has a self-learning capability such that the more information in the database, the greater the accuracy of the S.L.P.M.'s.
A prototype system has been developed and is currently undergoing trials, using data generated by laboratory rig, together with simulated data.
Economics of the Delaware-Val Verde Basin Deep Gas Play
Authors: Fish George E. 
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.
This paper was prepared for the 43rd Annual Fall Meeting of the Society of Petroleum Engineers of AIME, to be held in Houston, Tex., Sept. 29-Oct. 2, 1968. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal provided agreement to give proper credit is made. provided agreement to give proper credit is made. Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.

Abstract
During the past several years the oil industry has developed large gas reserves in the Delaware-Val Verde Basin. This effort required a large investment in men and material.
A minimum of 18,300 billion cubic feet of gas has been found and developed for an expenditure of 775 million dollars in direct costs. The rate of return on this investment should equal 9%, which is less than the average rate of return derived from all investments by domestic producers.
The current discovery rate promises important new reserve additions. However, as the more obvious features are drilled the undiscovered accumulations will become harder and harder to find. This factor plus the current inflationary trend for goods and services is expected to hold the rate of return at its present level.

Introduction
Eighteen years ago the exploration emphasis in the Delaware-Val Verde Basin shifted from the search for shallow (2,500' to 6,000') Delaware Sand stratigraphic oil to the deep gas bearing Devonian and Ellenburger structural traps (12,000' to 25,000'). An early success at Puckett, coupled with the discovery of Brown Bassett a few years later, soured the oil industry into a massive campaign to find more Delaware Basin gas. Cash outlays for geophysical coverage, leases, and exploratory drilling nave been tremendous.
Are gas reserves being found in sufficient quantities to justify this large outpouring of money? If so, will industry obtain an adequate rate of return on its investment? What is the current trend of the exploratory success ratio? To answer these questions has been the primary purpose of this investigation.
A geographic area containing the elongated geosyncline known in the industry as the Delaware-Val Verde Basin was outlined. (Shown by Figure 1.) Beginning in 1950 and continuing through 1967, all investment directed toward finding and producing hydrocarbons in this area from formations of Wolfcamp age and older was accounted for by year.
Quality Improvement of Liner Cementations by Using Bottom and Top Plugs
Authors: Dreikhausen H. 
Published: December 2007

ABSTRACT
An examination of cement samples from the top and bottom of liners and statistical studies of all liner cementations since 1982 clearly indicated that for long liners (approx. 1000 m) the cement was of poor quality and that for longer liners (up to 2200 m) cement contamination was so bad that the cement would probably never set.
As a result, a top and bottom wiper plug system was developed to prevent contamination of the cement inside the string while pumping the slurry. Repeated downhole testing and initial field experience resulted in improvements to the system, and the final design has been in field use since mid-1989. By December 1990, twenty-six 1" liners had been cemented using this system with a significant improvement in the quality of the cementation. The weight percentage of cement in samples taken from above the liner top using the old 2-Plug System was between 177» and 867&gt; and for samples taken from the liner collar/shoe it was between 377» and 877» depending upon the length of liner which was run. The use of the new 4-Plug System resulted in a weight percentage of cement of greater than 90% in samples taken from the liner top and the collar/shoe, irrespective of liner length.
This paper deals with the research, development, and field experience associated with the use of a four plug liner cementation system.
SIPM Practice for Site Specific Structural Fitness for Purpose Assessment of Jackup Rigs
Authors: Sliggers P. G. F. 
Published: December 2007

ABSTRACT
This paper describes the practice adopted by Shell Internationale Petroleum Maatschappij (SIPM) for the site specific assessment of jack-ups in elevated condition. In particular it addresses the structural engineering considerations that lead to a systematic approach for site specific analysis, condition assessment and condition monitoring of the jack-up structure. Experience with the approach has shown that through proper planning and timely execution of the work there needs to be little or no disturbance to the schedule of normal drilling operations.
Re-Entry and Relief Well Drilling To Kill an Underground Blowout in a Subsea Well: A Case History of Well 2/4-14
Authors: Ølberg T. , Gilhuus T. , Leraand F. , Haga J. 
Published: December 2007

ABSTRACT
Well 2/4-14 in the Norwegian Sector encountered well control problems in January 19S9 at a depth of 4734 m. After some days effort to reestablish normal pressure control the well blew out on surface of the floater and had to be closed in using the shear ram. This left the subsea BOP closed and with a shut in wellhead pressure of 10000 psi. In addition a full string of drillpipe with approximately 4500 m of coiled tubing was left in the well. After an attempt to regain control by bullheading heavy mud, in which a flexible kill line bursted, the well was left for a periode. Preparations were made to reenter the well with high pressure snubbing equipment to fish out the drillpipe and coiled tubing, so that the well could be circulated dead. In parallel to this effort a relief well was started immediately.
After the well was reopened it was discovered that the casing had bursted and that the well was blowing out underpound.
On December 12, 1989, 295 days after the shear ram was closed, the well was killed.
Another four months were required to finish cleanup and final abandonment of the blowout well.
The paper presents the case history and indicates some of the tools and technology that was developed to regain control of this well.