bluuebunny/crossref_metadata_2025_split huggingface dataset:
A New Development in Oil Recovery Polymers
Authors: Fratt W.J. , Bernot R. 
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.
This paper was prepared for the Rocky Mountain Regional Meeting of the Society of Petroleum Engineers of AIME, to be held in Denver, Colo., April 7–9, 1975. 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
A recent development has made it possible to use high molecular weight polymers in a liquid, rather than solid form. A comparison of the particles of a solid and a liquid polyacrylamide is made with micrographs of polyacrylamide is made with micrographs of each presented. The effect of these particles on handling and solubility is then discussed. Also presented are viscosity comparisons between liquid and solid polymers, as well as comparative core flood data and a discussion of the results. Reference is made to recently issued patents relating to oil recovery utilizing liquid polymers. Also, brief reference is made to field injectivity projects in various parts of the country. projects in various parts of the country

Introduction
High molecular weight polymers have evoked considerable interest in recent years for oil recovery operations, both secondary and tertiary. Polysaccharides and partially hydrolyzed polyacrylamides have been tested, both in the lab and in field trials to aid in recovering oil left in the reservoir.
While many questions still remain to be answered about what occurs in the reservoir, many operators have enhanced their oil recovery through the use of polymers in secondary and tertiary recovery projects.
Some oil companies are licensing their technology in tertiary recovery methods, making use of polymers to serve as the dive fluid to more efficiently push the surfactant or micellar flood through the reservoir.

USE OF SOLID POLYMERS
Oil recovery polymers are generally very high molecular weight; at least 1 million and greater. Until recently, only dry polymers were available for oil recovery projects. polymers were available for oil recovery projects. To use the dry product effectively, particular care and attention must be given to the handling and make up procedures required to put them into solution. Solid polymers have a justifiable reputation of being difficult to dissolve.
Increasing Oil Recovery by Chemical Control of Producing Water-Oil Ratios
Authors: Sloat Ben 
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.
This paper was prepared for the Rocky Mountain Regional Meeting of the Society of Petroleum Engineers of AIME, to be held in Denver, Colo., April 7–9, 1975. 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
Natural water drive reservoirs, normally considered quite efficient, have not been subjected to extensive oil recovery improvement studies or field tests. Lately, however, special treatments to control the producing water to oil ratios in Tensleep sand and Arbuckle Dolomite have shown good payouts. These results are presented payouts. These results are presented in the form of time-rate production graphs and cost performance tables.
Conclusions are:Ultimate oil recovery from natural water drive reservoirs can be improved by chemical treatments to reduce water-oil ratios.New in situ polyacrylamide gelling techniques provide an effective degree of control over subsurface water movement.Chemical oil recovery costs under $.95/bbl can be expected for natural water drive limestone reservoirs.

Introduction
Three factors — higher crude oil prices, better technology and lower prices, better technology and lower treatment costs — have been combined to assure excellent payouts from producing wells treatments designed to producing wells treatments designed to lower water-oil ratios in natural water drive reservoirs. This paper studies the effect of each factor on a group of Arbuckle "control" wells in the Graham-Rooks County area of northwest Kansas (Fig. No. 1). Treatment of a Tensleep sand producer in Hot Springs County, Wyoming, is also summarized to show that good economics can be expected under a variety of reservoir rock and fluid conditions.
ARBUCKLE DOLOMITE — GEOLOGY AND PRODUCING CHARACTERISTICS PRODUCING CHARACTERISTICSAn important subsurface feature in central Kansas is the Barton Arch — a buried ridge of Precambrian granite running northwest-southeast. Above this basal granite lies the Cambro-Ordovician Arbuckle Dolomite, the principal oil producing zone in central Kansas.
Development of a Portable Downhole Camera System for Mechanical Inspection of Wellbores
Authors: Whittaker J. L. , Schultz P. K. , Baker D. L. 
Published: December 2007

Summary
A second generation, highly portable, downhole video camera system for mechanical inspection of wellbores has been successfully tested and field deployed in several global locations. The technology employed is unique from previous camera inspection systems in that it can be deployed on conventional wireline and has a fast data rate providing images every 3.5 seconds independent of cable length. This technology provides operators in remote locations a 舠fly away舡 diagnostic tool providing visual information of downhole problems and conditions. Visual inspection of downhole problems provides clear, definitive information, giving operators the highest possible confidence in remediation of problem wells. Because any conventional cable can be used, this camera system will provide video inspection when: 1) the well depth is too deep for full motion video systems, 2) corrosive fluids are present, 3) temperatures above 300°F are present, 4) the well is horizontal and the tools can only be deployed by coiled tubing or well tractor, and 5) rapid deployment is necessary including remote locations where other camera systems could not be mobilized on short notice.
Geological History of the Northwest Passage
Authors: Daae H.D. , Rutgers A.T.C. 
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.
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
The broad structural geology and stratigraphy of the Northwest Passage is controlled by the Boothia Arch and structural depressions on each side, namely, Viscount Melville Sound and McClure Strait to the west (graben) and Lancaster Sound to the east (half-graben). Negative rift movements began during Mesozoic time and continued into the Tertiary.
Outcrop and well information from the islands are related to marine seismic data in the Northwest Passage. Paleozoic strata appear to continue offshore in facies predictable from data on the islands. Mesozoic and Tertiary strata, however, are represented by sparse remnants on land, but are well developed under Lancaster Sound, if low velocity beds present there are of these ages. M'Clure Strait also seems to have thicker Tertiary and Mesozoic sediments than do the adjacent islands.

Introduction
The study area is large (Fig. 1). it occupies a region 900 miles long by 300 miles wide. An effort has been made to incorporate all literature on outcrop data as published by the Geological Survey of Canada and indus together with well information released to the public. These sources of data were combined public. These sources of data were combined with 14,000 miles of marine seismic information obtained throughout the Northwest Passage. At the time of writing no offshore wells have yet been drilled in the Northwest Passage.
Fig. 2 shows the main geographic divisions. From east to west they are: Lancaster Sound, Barrow Strait, Viscount Melville Sound, and McClure Strait. The width of these sounds is approximately 50 miles, locally widening to 130 miles in Viscount Melville Sound, and narrowing to some 30 miles in Barrow Strait.

PALEOZOIC STRATIGRAPHY PALEOZOIC STRATIGRAPHY

Cambrian
The Cambrian lithofacies and isopach map, Fig. 3, shows the Minto Arch, the Boothia Arch, and a third area named the Stable Shelf. The Stable Shelf is that area which was not greatly affected by post-Precambrian orogenic movements. It underlies the eastern part of Devon Island, northern Baffin Island and Bylot Island. Late Proterozoic sediments outcrop along the Minto Proterozoic sediments outcrop along the Minto Arch, whereas crystalline rocks of Archean age are predominant on the Boothia Arch and Stable Shelf, with local outcrops of late Proterozoic sediments.
ICoTA's CT Drilling Training and Competence Guidelines - How to Use Them
Authors: Bijleveld A. F. 
Published: December 2007

Abstract
This paper describes the development and use of the International Coiled Tubing Association (ICoTA) guidelines for training and competence for CT drilling operations.
The lack of training standards within the coiled tubing industry is well recognised. In order to redress this and develop standard training requirements for CT operations ICoTA set up a workgroup in 1997. The aim of this workgroup was to identify the minimum required skills and knowledge for safe and efficient CT operations, to aid the training of personnel and enhance operational safety and efficiency. Initially CT Drilling operations are addressed as this is the area where the lack of a structured approach to training and competence is most apparent.
The paper discusses the results from this workgroup, and presents the suggested outcome. The approach to wellsite competence is based on competence presence, and is not related to people or job functions. Three levels of competence are recognised; ability to execute, ability to supervise execution and ability to assist. The guidelines take into account; applicability worldwide for all CT drilling operations, on all types of CT units, and different organisational structures.
Several examples of training requirements will be given for various CT drilling operations in order to illustrate how this document may best be used in practice.

Definition:
This paper is about training, competency and experience.
To achieve a common understanding of the definition of competency it is taken as meaning:
Competency – " Ability to perform the activity in the workplace consistently to the required standard ". In this context, competency consists of proven knowledge, skills and experience.
The All Electric BHA: Recent Developments toward an Intelligent Coiled-Tubing Drilling System
Authors: Turner Daniel R. , Head Philip F. , Yuratich Michael A. , Cameron Gerald 
Published: December 2007

Abstract
This paper considers the ongoing development of an electrically powered bottom hole assembly that has been designed for use in closed-loop, coiled tubing drilling (CTD) applications.
The electric BHA has been conceived and designed through a European Drilling Engineers Association [DEA(E)1] joint industry project. This paper introduces the project and reviews its progress to date.
Electric coiled tubing drilling, or E-CTD, was delineated as a three phase project to stage progress and reduce technical risk. Phase I of the project, completed in late 1997 was designed to prove the feasibility and concept using standard motor technology.
Phase II, currently in a bench testing programme, intends to deliver a fit-for-purpose electric downhole motor (EDM) suitable for drilling a 3.75″ hole. The motor is being incorporated into an electric bottom hole assembly (BHA) which incorporates pressure, temperature and vibration sensors. This is shortly to be field tested in Aberdeen.
Phase III of the project, scheduled to start mid-1999, integrates geo-steering and variable-bend directional technology to provide what has been termed the ‘all electric’ BHA. The ultimate goal of the project is to integrate the electric motor into a closed-loop drilling system. It is envisaged that, based upon feedback from near-bit sensors, such a system would be able to automatically adjust drilling parameters to optimise drilling performance.
Upon successful completion of basic closed loop functions, the intention is to incorporate the controlability of the BHA into what they describe as an ‘intelligent’ drilling system. This paper outlines a definition of this ‘intelligence’ and the authors also provide an insight into how far they believe that this technology may be taken, in terms of the autonomous decision making ability of a surface computer.
Coiled Tubing Failure Statistics Used to Develop Tubing Performance Indicators
Authors: Adrichem Willem P. van 
Published: December 2007

Abstract
Unpredicted CT string failures have not completely disappeared despite the industry having a greater understanding of cycle fatigue. A comprehensive process to systematically analyze CT string failures (field-based) has been in place since 1995. This system is described and details of a CT string failure database discussed. The database includes over 120 entries from the period 1995 through 1998 derived from worldwide CT operations of Schlumberger Dowell. The process delivers two principal data sets: the mode of failure (failure mechanism) and the cause (failure cause).
The four-year study period enables failure trends to be identified. Such trends are evident in both in failure mechanism and cause and are discussed.
Evaluating the "expired life" of the CT strings under study has led to the conclusion that traditional and current string management procedures (that are based on low cycle fatigue accumulation) are inadequate. This has implications in both the prediction of CT string failure and the optimization of string use.
The CT string failure data is derived from CT operations conducted by over 150 CT units that completed in excess of 35,000 operations during the study period. The volume of tubing used during these operations, in combination with the accumulated failures, allows for the introduction and discussion of "Tubing Performance Indicators", which the author believes can be considered representative for the industry.
Oil-Based Reservoir Drilling Fluid for Critical Field Cases: Integrated Formation-Damage Evaluation and System Development
Authors: Hanssen Jan Erik , Ping Jiang , Haga Marton , Berge Hans Ivar , Boassen Tony , van der Zwaag Claas 
Published: December 2007

Abstract
An increasing number of field developments in Norwegian waters are marginal, with the economics limited by reservoir deliverability and requiring optimum well productivity unaffected by formation damage. This paper presents a case history from an ongoing development in low-permeable, highly challenging reservoirs. The 150 °C downhole temperatures, well geometry restrictions imposed by the subsea development, and the use of non-perforated completions place additional constraints on fluid design. The focus of the paper is on formation damage studies and the identification of performance-critical drilling fluid parameters. The development of representative laboratory methods is discussed and uncertainties evaluated. The joint study highlights the importance of using a range of field and lab mud preparations and working in an open interactive manner for fluid development, evaluation and testing. Combining field and laboratory test results was a critical part of the effort.
Initial mud exposure tests on reservoir core samples indicated that an otherwise qualified HTHP oil-based drilling fluid could cause severe formation damage in this particular reservoir. This was quite unexpected, as the fluid in question has been used to drill highly productive wells in other fields. Similar damage was observed on field and laboratory mud samples. Parallel work showed selected water-based fluids to also be damaging with no other decisive advantages. A systematic program of reformulating the HPHT OBM was undertaken. First, each auxiliary system component was replaced, and the effect on formation damage measured. These changes were insufficient to remove the damage potential of the original fluid. Therefore, an alternative emulsifier pack-age was selected and used as the basis for designing a novel system. Core tests on lab formulations of the novel system indicated greatly reduced formation damage potential.
A field trial was immediately carried out to validate the novel system and showed good production potential with low skin damage. A repeat test in another well confirmed this observation. The field trials were designed to capture any changes in field fluid behavior that could be detrimental to well productivity. Drilling-fluid samples were collected at regular intervals and characterised for standard properties, filtration, particle sizing and formation damage. Supporting research, using powerful experimental tools such as ESEM, and pore-size analysis of reservoir cores gave added value. Surprising core-test results led to the identification of flaws in the lab test protocols affecting the saturations before and after mud exposure. By redefining the core-test procedures and correlating all the lab results, conclusions were obtained that were in agreement with the good field performance of the novel fluid and new knowledge was gained about the mechanisms of formation damage.
Ball Sealer Diversion When Fracturing Long and Multiple Triassic Sand Intervals on Alwyn Field, North Sea
Authors: Baylocq Pascal , Fery Jean Jacques , Parra Laurent , Derbez Emmanuel 
Published: December 2007

Abstract
This paper presents results related to the use of the ball sealer diversion technique to fracture long and multiple Triassic sand intervals in the Alwyn Field. It also focuses on the methodology adopted to design and prepare the treatment.
This technique was applied on a well producing from a gross pay zone thickness of 350 m with a perforated length of 98 meters. The production decreased drastically after condensate deposition in all reservoir intervals induced high skin levels. Due to low permeability, matrix treatments were discarded as a solution. Instead, a proppant fracture treatment was planned to by-pass the skin, using ball sealer diversion to treat the entire perforated interval.
The treatment was performed successfully in several stages including gel pad, proppant and ball sealers. Good indications of diversion showed that most of the intervals were fractured. However, performing such a treatment requires sophisticated engineering to determine the optimum number of stages, number of ball sealers per stage, gel and proppant volumes per stage and pumping rate.
The success of this operation will allow the technique to be considered for wider application such as fracturing long intervals in deviated or horizontal perforated wells at moderate cost.
Direct Digital Laserlogging
Authors: Burgen Jack G. 
Published: December 2007

Abstract
This paper describes a newly developed, direct-digital system for monitored data acquisition, automatic computation and calibration of well log data with presentation on an entirely new Laser Beam graphic recorder. The new direct-digital system avoids the errors that are sometimes made by field engineers when faced with the multitide of switches, connectors, adjusting knobs and meter dials of conventional analog panels, as well as errors due to analog drift and nonlinearity. Many older systems have utilized a computer to "process" the data provided by the conventional analog panels, but processing by these hybrid systems does not avoid the errors that are inherent in the analog panels and in the adjustment of the analog knobs and dials during calibration and operation. The new system described in this paper, is digital from the start, avoids the knobs and dials and provides automatic calibration and quality control, resulting in precisely repeatable records. The Laser Beam photographic record is completely ready for use within a few seconds after the recorder receives the input data.
The steps involved in reaching this degree of refinement are generally analogous to those experienced in seismic exploration operations during conversion to digital methods; digital processing of data from standard analog truck equipment only prefaced the present direct-digital field equipment, which has made vastly improved data processing possible.