bluuebunny/crossref_metadata_2025_split huggingface dataset:
Hydrocarbon Potential Of The Trinidad Area
Authors: Persad K.M. 
Published: December 2007

Abstract
It is now recognised that deltaic and associated sands, together with porous marine limestones, form the vast majority of the reservoirs in the major accumulations of hydrocarbons throughout the world.
The source of the hydrocarbons is now thought to be kerogen which is generated from the organic content of principally marine shales which are formed in or near the continental shelves.
The Trinidad area contains several sedimentary sub-basins, most of which consist in large of deltaic and associated sediments. These sediments, like most of the ancient deltas of the world, contain major reserves of oil and gas. Other less important reserves should occur in sporadic (time-wise) porous limestones.
The total probable reserves of the Trinidad areas exceed 7 billion barrels of oil and 35 trillion cubic feet of gas.

PETROLEUM POTENTIAL IN THE TRINIDAD AREA PETROLEUM POTENTIAL IN THE TRINIDAD AREA ORIGIN OF HYDROCARBONS
Current thinking assumes that in large part petroleum is generated in marine shales which are relatively rich in organic content Briefly, the organic content is changed under reducing conditions to kerogen or a kerogen-like substance which is the presursor of petroleum and petroleum like products. The kerogen petroleum and petroleum like products. The kerogen under the correct conditions of pressure and temperature, is then converted to hydrocarbons. These conditions are generally met if the shales are buried to several thousand feet in an area of normal temperature gradients. The hydrocarbons are generally thought to migrate soon After generation into whatever reservoir rocks lie nearby.

RESERVOIR TYPES
In broad terms two types of reservoir rocks trap over 95% of the known hydrocarbon accumulations. These are sandstones and limestones.
The majority of these accumulations are found to be those associated with deltas and porous limestones. The reasons for this are:They generally interfinger with organic marine shales which act as source rocks andThey are broadly either lenticular in nature or affected by growth faulting and/or folding caused by plastic flow of underlying shales, i.e. shale diapirism plastic flow of underlying shales, i.e. shale diapirism (in the case of deltaic sands) so that traps exist even before hydrocarbon generation and migration begin.
In other words, all the pre-requisites for hydrocarbon generation and trapping are generally present in areas of deltaic deposition or where limestone deposits interfinger with highly organic marine shales.
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Evaluation Of Cathodic Protection Systems For Offshore Structures
Authors: Edmonds A.T.G. , Higgins F.A. 
Published: December 2007

A number of papers have been written and presented dealing with the detailed methods of calculating and applying cathodic protection to offshore structures. In this paper it is our intention to consider the technical qualities of the materials and systems available and compare these commercially.
The term offshore structures as used in this paper specifically refers to fixed drilling and production platforms and mobile drilling rigs.

Cathodic Protection
Cathodic Protection can be defined as the reduction or prevention of corrosion of a metal (e.g. steel) in an electrolyte prevention of corrosion of a metal (e.g. steel) in an electrolyte (e.g. sea water) by introducing an additional anode system from which electrical current will flow into the electrolyte and onto the corroding metal surface reducing or preventing the natural corrosion current flow from anodic areas to cathodic areas on that metallic surface. The protective current may be obtained from the use of highly electronegative materials such as magnesium, zinc or aluminium or by the use of relatively inert anodes with an external direct current power source. The former is termed sacrificial anode cathodic protection, the latter impressed current cathodic protection. protection. Steelwork Requiring Cathodic Protection Cathodic Protection should be considered for steel when it is:Totally immersed in water.Buried in the seabed or shore (i) in the bare condition or (ii) in the coated condition.Associated with or immersed in concrete when it is either (i) in the bare condition or (ii) in the coated condition.
Combinations of the above may also require cathodic protesion. protesion.

Cathodic Protection Systems
Sacrificial Anode Materials The following alloys are used as sacrificial anodes:Aluminium alloys.
These can be considered to be split into certain generic types. heat treatment aluminium zinc tin alloys, aluminium zinc mercury alloys and aluminium zinc indium alloys. Table 1 indicates some typical specifications.
Selection and Sensitivity Requirements for Blowout Control Detection Instruments
Authors: Dittmer Albert K. , Fisher F.J. 
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

Abstract
In blowout control and prevention planning, the prime detection instrument needs to planning, the prime detection instrument needs to be designated and its minimum sensitivity specified. Sensitivity requirements will depend on the drilling environment, i.e., casing depth, reservoir properties, mud underbalance possibilities, rig reaction time, circulating rate, etc. Through use of a computer program (KIKSIM) that quantifies the transient characteristics of hydrocarbon gas in the annulus of a drilling well, comparisons are made of detection instrument alternatives.

Introduction
In an earlier paper, the computer program KIKSIM was used to illustrate how program KIKSIM was used to illustrate how changes in mud circulation rate can aid in well control. The KIKSIM program which develops information concerning the transient characteristics of hydrocarbon gases in the annulus of a kicking well also has considerable value in planning. Among the planning decisions that can be improved with KIKSIM are selection and establishing specifications for mud flow sensors and pit level recorders. The concept of warning time is introduced and stressed.
This report deals with the detection of gas in the annulus in drilling ahead situations. It does not deal with detection of formation fluids during trips which is a distinctively different problem.

DETECTION STAGES
In drilling ahead situations formation gas in the borehole can be detected and measured at three stages, which we will refer to as the entry, mud transport and "expansion burst" stages.
Obviously it is to our advantage to try to detect gas as soon as possible, e.g., as it enters the borehole. Since we may at times be dealing with relatively small volumes at bottomhole conditions, this may not always be possible.
The second stage during which we may detect gas is during mud transport of the gas up the hole. As mud transports gas up the hole it slowly expands and this expansion can be used to detect gas. The mud transport stage is arbitrarily defined as that period during which the rate of gas ascent is largely (2/3) determined by the mud circulation rate.
An Acoustically Controlled Down-Hole Safety Valve (SCSSSV)
Authors: Pedigo John , Parker William H. 
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

Abstract
A surface-controlled subsurface safety valve (SCSSSV) system without external wires or hydraulic lines needed for the valve's operation is now available to the petroleum industry. Any of the current down-hole safety valves, such as Hydril, Otis, Camco or Baker, can be fitted to the valve operator. This is a totally fail-safe valve system, which can be overridden manually at the operator's choice to accomplish a number of different modes. The valve's operator is acoustically controlled by the operator's predetermined settings at the surface. The predetermined settings at the surface. The receiver, translator, and valve actuator are packaged and placed in a special mandrel that is packaged and placed in a special mandrel that is run as a part of the tubing string. The hydraulic valve operator is mounted on a length of production tubing between the mandrel and valve. The full-flow valve is at the bottom of the down-hole string. Any length of production tubing may be run below the valve. Hookwall hangers can be run in as may be needed.
The down-hole electronics is a module set in a side-pocket mandrel with wireline equipment. Setting depth can be below "paraffin" zones. The system does not reduce production flow and will permit other wireline operators to pass to other equipment below the setting depth.

REVIEW OF THE STATE OF THE ART
With the movement of the oil industry into the more or less hostile environment of offshore operations, it was apparent immediately to the oil operators that an automatic "fail-safe" valve was needed for the producing oil or gas "flow string".
A valve was produced that would respond to changes in flow rate either above or below levels preset into the valve. The first valve to be so adapted and so employed was the differential pressure, spring-loaded valve. Abnormal increases in the flow rate across the valve caused it to close. This valve was very simple in construction, could be set in the production string and removed by means of a production string and removed by means of a wireline. The differential pressure valve and its "sister" valve, the ambient pressure valve, which closed automatically if the rate of flow or resultant pressure across the valve dropped below a preset valve. These safety valves became known to the oil industry as "storm chokes", but actually the term "storm choke" is a registered patent term; therefore, such valves should only be referred to as down-hole production string safety valves. production string safety valves.
Continuing Education Programs Past, Present and Future
Authors: Chapman P.F. 
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

Abstract
Continuing Education for petroleum engineers and related professionals has increased significantly in scope and content during recent years. This activity is a response to the need for maintaining technical competence, and supplying new information, to practicing engineers during a period of rapid technological change. The Society of Petroleum Engineers established a standing committee in 1965 to develop programs for members of SPE. This program is discussed and current thinking about present and future programs explained. In addition, specialty programs presented by Universities, programs presented by Universities, consultants on a commercial basis, and by companies on an internal basis are reviewed.

Introduction
Continuing Education is a term that means different things to different people, and is described by many different terms. Continuing Education, Continuing Engineering Studies, Life-time Learning, Post-degree, Non-traditional, Adult Education Post-degree, Non-traditional, Adult Education and others are common terms, and used sometimes interchangeably. It is thought of commonly as any educational activity that occurs after formal full-time education ends.
In this paper, the term Continuing Education refers mostly to non-credit technical programs in the form of short courses and packaged programs for technical professionals in the oil and gas producing industry. And these professionals producing industry. And these professionals include the majority of the 23,000 members of the Society of Petroleum Engineers. These professionals have a variety of degrees, including non-engineering degrees, but in some cases can have extensive experience instead.
The scope of continuing education is large and growing. Because of diversity and a lack of structure, it is difficult to characterize, define, or describe. Continuing education is mobile.
An Iterative Solution for the Gas Pipeline Network Problem
Authors: Crafton James W. , Dyal Victor H. 
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

Abstract
To make steady-state gas pipeline network analysis a useful design and planning tool, it is essential that the planning tool, it is essential that the numerical solution procedure meet two important criteria:Assurance of rapid solution convergence, and uniqueness, thus economical solution costs andFlexibility in handling a wide variety of piping, loop, and compressor configurations encountered in gathering and transmission networks.
If these criteria are satisfied, a simulator useful for supply and demand optimization, allocation or proration evaluation and compressor optimization is achievable.
The steady-state methods presented in the existing literature fall in two classes, either direct-explicit replacement schemes or Newton-Raphson iterative methods. The scheme described in this paper is an iterative procedure which employs the connected nature of a network to achieve efficient computer storage and rapid solution for the pressures and volumes in the system. The pressures and volumes in the system. The method for solving complex looped pipe line systems and unconstrained or "loaded horsepower" compressors is developed. The results of this technique are exhibited by the solution of a sample gathering system, with interconnected loops containing large compressors.

Introduction
As the need for increasingly efficient utilization of natural gas occurs, tools capable of handling the resulting problems are needed. One important area problems are needed. One important area lies in the evaluation of system operations and design for a natural gas pipe line network. Regardless of the task, a rapidly convergent solution scheme for solving the systems of nonlinear equations describing the network is required. Two solution procedures appear to be in general use for the steady-state problem.
Natural Gas Production from Geothermal Geopressured Aquifers
Authors: Isokrari Ombo F. 
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

Abstract
The energy crisis has resulted in an increased interest in the use of alternative energy sources for electric power generation. Geothermal energy is commonly mentioned as a supplement to existing and projected major sources of fuel. A unique form of geothermal energy exists in geopressured aquifers underlying the United States Gulf Coast. Water from such geopressured aquifers often contains natural gas. This paper deals with the production of natural gas from such reservoirs. production of natural gas from such reservoirs. We have classified geothermal geopressured reservoirs into three types based upon the natural gas content. In Type 1, the reservoir water is undersaturated with natural gas. However, it could still contain more than 40 standard cubic feet of natural gas per reservoir barrel of water. In Type 2, the reservoir water is fully saturated with natural gas and the reservoir may contain a small gas cap. Type 3 is a geopressured gas reservoir. The water is nearly immobile in the reservoir but the adjacent and underlying shales contain water with gas in solution, that may move into the reservoir. Producers have been most interested in Type 3.
This paper presents computer studies of the production of multiphase fluids (natural gas, gas in solution and water) from geothermal geopressured reservoirs.
The two phase, two dimensional simulator was developed for simulating reservoir production behavior of both nonisothermal and production behavior of both nonisothermal and isothermal deformable reservoirs, and can be used for areal or cross-sectional studies.
Computer runs were made to generate a variety of data. For Type 1 and Type 2 reservoirs, reservoir pressure variations with natural gas and water production were generated. It was found that substantial amounts of natural gas can be produced over a long period of time. Where the water is hot enough the accompanying water may be used to generate electrical energy or for space heating or desalinated for agricultural purposes.
The model was used to make areal studies of a bounded hypothetical geopressured gas reservoir, with no shale water influx using different compaction coefficients. It was found that BHP/Z versus cumulative gas production curve changed significantly with production curve changed significantly with increase in compaction coefficients.
The model was also used to make cross-sectional studies to assess the effect of shale water influx from adjacent and underlying shales.
Finally the model was used for simulating the reported production history of Anderson 'L', a geopressured gas reservoir in south Texas. Good agreement was obtained between the observed BHP versus cumulative production as well as BHP/Z versus cumulative production.
Production Logging through the Annulus of Rod-Pumped Wells to Obtain Flow Profiles
Authors: Hammack Gregory W. , Myers Brent D. , Barcenas Gilberto H. 
Published: December 2007

INTRODUCTION
Historically, downhole production surveys have been run through tubing, after pump and rods have been pulled and the well swabbed, or through the tubing-casing annulus after replacing existing tubing with a small diameter string. In both cases, normal well pumping conditions have been altered to the extent that many production surveys probably have not been representative. Running a production survey while a well is pumping under stabilized conditions allows observation of normal pumping fluid inflow performance. To this extent, a small diameter (7/8 in. oD) combination production logging tool is being used successfully to determine the following:Temperature ProfileInflow Velocity ProfileFluid Density
The configuration of the tool allows it to be used in small tubing-casing annulus sizes such as 5 1/2 in. OD casing and 2 7/8 in. EUE tubing. This paper discusses the tool's specifications and configuration, applications and results which are illustrated by field examples.

TOOL DESCRIPTION
The combination production logging tool has four basic modules that can be run in tandem: a) casing collar locator; b) radioactive tracer section; c) temperature probe; and d) fluid density section (see Figure 1).
The outside diameter of the tool is 7/8 in with a total length of approximately 20 feet. Construction is very clear with no protrusions in the tool case that will cause snagging or hanging up on tubing collars.
Application and Economics of Artificial Lift in the Judy Creek Field, Alberta
Authors: Steele Robert D. 
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

Abstract
Well productivities in the Judy Creek Field in Alberta, Canada range from very good (PI = 290 BPD/psi) to poor (PI less than 1). To obtain high lift efficiency, and low-cost well performance, Imperial Oil Ltd. used engineering and economics to select three artificial lift methods for Judy Creek. High capacity wells near the high pressure gas supply are on gas lift. High capacity pressure gas supply are on gas lift. High capacity wells in more isolated areas of the field have been equipped with submersible pumps. Lower productivity wells throughout the field are productivity wells throughout the field are equipped with sucker-rod pumps.
Well analysis is the important first step in the selection of a lift method. The analysis techniques used in Judy Creek are discussed and then applied to the design and evaluation of the three types of lift. Background to the economic comparison of gas lift to submersible pumps is included. pumps is included

Introduction
The Judy Creek reservoirs are located 130 miles northwest of Edmonton, Alberta, Canada (Fig. 1). The field was discovered in 1959. The two reservoirs, the larger "A" Pool and the "B" Pool, will be simply referenced as Judy Creek. Pool, will be simply referenced as Judy Creek. The reservoirs are a stratified limestone reef of the Upper Devonian age. The two pools have 629 MMSTB of recoverable oil.
Most of the discussion will concern two areas in the larger "A" Pool. The high productivity area (Fig. 2) is a high-porosity, fore-reef rubble. Wells typically have productivity indices (PIs) greater than 20 BPD/psi. The pattern waterflood area is a stratified lagoon with PIs normally an order of magnitude lower than the high-productivity area.
The field was drilled to a well spacing of 160 acres. Drilling in the early 1970s reduced the well spacing in the high-productivity area to 80 acres. At the end of 1975 the field had 30 submersible pumps, 25 gas lift wells, and 24 sucker rod pumps.
A peripheral, downdip waterflood was installed on the west side of both pools in 1963 and 1964. Beginning in 1969 productivity was supplemented, as market demand increased, by the installation of submersible pumps.
The pattern waterflood was installed in 1974 following extensive geological and reservoir work. Well productivity in the pattern waterflood area increased from 20,000 to 35,000 BOPD in less than one year.
Comprehensive Analysis Of Drillstem Test Data With The Aid Of Type Curves
Authors: Sinha B.K. , Sigmon J.E. , Montgomery J.M. 
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 discussions may be considered for publication in one of the two SPE magazines.

Abstract
A substantial percentage of drillstem tests cannot be analyzed by conventional methods due to insufficient data. Numerous tests have been analyzed by several published type curves.
In this paper, many examples are included where the application of the appropriate type curve aided in providing correct analysis of data which providing correct analysis of data which otherwise may have been misinterpreted.

Introduction
The importance of the decision based upon drillstem test results regarding the-probability of commercial production from a well cannot be production from a well cannot be over-emphasized. This vital decision requires that available data be analyzed thoroughly to provide a high degree of confidence in the analysis. Due to various reasons, it is not often possible to assure availability of sufficient data to complete a conventional Horner analysis with confidence. Under these situations, the recent type curve matching techniques are being used for analyzing incomplete drillstem test data.
Since 1970 several type curves have been published for analyzing early time data from pressure transient tests. The majority of the literature on type curves application is oriented toward long duration tests (which are usually conducted later in the producing life of a well) and not toward drillstem tests.
There are several problems which are common to drillstem tests:occurence of critical flowpresence of superchargeusually short testing durationquestionable production datamechanical problemsdrastic variations in bottom-hole pressurespresence of more than one producing zonelack of reservoir and fluid properties data at the time of the test