bluuebunny/crossref_metadata_2025_split huggingface dataset:
New Method To Read and Correct the API Gravity of Oil From Observed Temperatures to 60°F (includes associated paper 28944)
Authors: Keaves Sonny V. 
Published: June 2014

This graphical interpolation method is plotted directly from the American Soc. for Testing and Materials (ASTM) tables. The method, a one-step procedure and direct reading, is easy and quick. It is difficult to make errors. No calculations are involved, which is not the case for the method described in the ASTM manual. The usual calculation method can easily and frequently cause errors, and few enjoy consulting the manual to do the calculations for checking. If you have not used the calculation method in a while, you probably will need to review the instructions and examples again. Taking the time to do so is difficult when you are busy.
The graphic chart in Fig. 1 is one of many I created on a PC to describe the new method. Remember, API gravity is measured from 0 to 1000API and from 0 to more than 150°F (ASTM tables stop at 150°F). If one chart contains 20 curves from 0 to 75°F, a total of approximately 10 charts will be needed to cover the full temperature and API ranges.
The following examples show how to read the chart.
Example 1. (Same information as Example 1 in the ASTM manual, Appendix C.) Find the API gravity at 60°F for 38.400API at an observed temperature of 76°F.
Solution. Enter the 38° API line down to the observed temperature of 76°F, divide the distance from this line to the next line above it by 10 (each division is a 0.10), mark 0.40 on that scale and add 38 to make 38.40, and then read directly from there. Point A is 37.200API at 60°F of the 38.40° API at the observed temperature of 76°F.
Example 2. Find the API gravity at 60°F for 41.50° API at an observed temperature of 79°F.
Solution. Enter the 41.00° API line down to the observed temperature of 79°F. Repeat the next step from Example 1. You will find that the API gravity at 60°F for 41.500API at 79°F is 40.000API, which is Point B.
Realising The Benefits Of Environmental Risk Management
Authors: Holgate M. , Mentzer E. , Garnham P. , Harris E. , Davies G. , Verburgh J. , Whitehead A. , Shepherd J. 
Published: June 2014

Abstract
The E & P industry is facing increasing costs from meeting its environmental responsibilities. European governments have collaborated with the industry to develop a harmonised scheme to model the environmental hazard of production chemicals.
It is proposed that the model be incorporated into a cost benefit analysis to prioritise environmental solutions. This opens the way for a goal setting regulatory framework as a means of targeting resources to achieve real environmental gains.
Production Enhancement Partnerships - Successful Business Arrangements
Authors: Coble Larry , Weitzel Kenneth , Attai Larry , Gray Kent 
Published: June 2014

Summary
Production enhancement projects are creating changes in business relationships between oil & gas and service companies. The most successful projects are building partnerships. Service companies are being asked to share the risk while supplying services to enhance well performance. Risk sharing creates common project objectives and requires the service company's involvement in initial project planning, job design, and reservoir understanding. Service work compensation is based on well or field performance improvement as a result of the treatment(s).
This paper presents an integrated approach to the selection and prioritization of well candidates for production enhancement jobs or treatments. Special emphasis is placed on reservoir understanding using field reviews and/or extensive reservoir description studies to provide the essential information for well candidate selection and the best return on investment. Processes are illustrated and discussion gives the data requirements and techniques used to select and prioritize well candidates. Field examples demonstrate the techniques, critical factors, and appropriate software used by geoscience and field operations teams to maximize benefits from production enhancement projects.

Introduction
The need for a better business arrangement with service companies has been identified by many operating companies. Partnerships evolved to align interests, utilize the same performance measurements, create an environment for teamwork, ensure use of appropriate technology and add value by increasing the project profitability.
The bidding process is being replaced with partnerships due to the realization that superior benefits can be obtained. In the typical ‘low bid’ scheme, the operator planned the project, designed the job and distributed the job specifications to several suppliers to bid the services and materials. In many cases, the operating company would select the vendor supplying the work based on the lowest price. This type of arrangement gave little incentive to the service company to enhance production. If the job went as designed, i.e., the service company was on time, brought the necessary materials, and performed the job within the specifications, the service company considered the job a success. However, the job may not have achieved the expected production increase for the operating company. Project profitability and continuous quality improvement can be compromised in this scenario.
The alliance/partnering business arrangement is an excellent vehicle to achieve continuous improvement and apply ‘best practices’ techniques.
Environmental Mandate Reform
Authors: White Ronald D. , Russell Barry 
Published: June 2014

Abstract
America's current system of establishing environmental mandates treats the concepts of a healthy environment and a strong economy as if they are mutually exclusive. Certainly a cheap, reliable source of domestic energy does not appear to be a high priority. A balance must be returned to the system by improving the governmental processes of risk assessment, risk management, and risk mitigation.
This paper describes the shortcomings of the current system and outlines the impact of the problems. Proposed improvements to the risk process are discussed along with possible implementation strategies.
Test Method for "Actual" True Vapor Pressure of Crude Oils
Authors: Henderson J. K. 
Published: June 2014

ABSTRACT
Currently, the "True" vapor pressure of crude oil is typically calculated via API 2517 temperature nomograph adjustments to Reid Vapor Pressure testing results (ASTM D-323-90). This "True" vapor pressure or simply vapor pressure for a given oil or fluid is of interest because it defines the point of vapor initiation (i.e., the boiling point or bubble point). The quantity of such oil vapors is of course directly related to product losses and environmental air emissions. It has been found that the Reid test even with the API 2517 adjustment for "True" vapor pressure gives 50% to over 300% errors in the determination of a crude oil's actual true vapor pressure.
Mitretek Systems, therefore, developed a test method with calculation algorithm that substantially improved the determination of a crude oil's "actual" true vapor pressure. The method involves use of a device to 1) analyze the composition of gas separating from a liquid oil stream at a known pressure and temperature, 2) measure the rate of gas and oil flow exiting the same gas/oil separator, and 3) use the described test data in an iterative calculation algorithm with industry-established gas/liquid equilibrium values to estimate the crude oil's vapor pressure within +/−2% (or 0.3 psia). This test method provides a characterization of the oil's composition which then allows prediction of vapor pressure as well as air emission quantities over the full temperature range of interest. In addition air toxics existing in the oil (H2S, benzene, etc.) have been quantified to the 10 ppm level in the oil as well as in the evolved gases.
Modelling and Operation Optimization and Flow Control of Large Scale Water Injection Systems
Authors: Miaoxin Chen , Yubo Duan , Congxin Li , Guangyu Si 
Published: June 2014

Abstract
This paper presents a new method for modelling and operation optimization of large scale water injection systems. Systems of tms Kma usually consist of a great number of water injection stations.pipelines.valves.pipe fittings,and water injection wells, and is a multi-source multi-sink nonlinear time-vaiying system with thousands of vanables. A properly simplified and sufficiently accurate mathematical model lias been made by both the analytical method and the system identification method. A new operation optimization method has been developed for this system by the large scale system theory and the dynamic programming method To solve this optimization problem.the concept of pressure valley in hydrodynamic system is presented for the first time in this paper. The water uniection system is divided into a senes of subsystems according to pressure valleys It has been proved 1 that system optimization on the whole is equivalent to optimization of every subsystem in it if coupling variables of the subsvstems have the values resulting from the optimized system. Thus, rhe system optimization problem is decomposed into a senes of subsystem optimization problems.
The above modelling method and operation optimization procedures are programmed in a software package. This package has been applied to an oilfield in Daqing Electnc power consumption for water injection decreased by 3- 10%,and waterflood efficiency improved.
Application of Well Test in Daqing Oil Field
Authors: Yongsheng Chen , Yaozu Wang 
Published: June 2014

Abstract
Well testing methodology was modified for Daqing field to account for the case in which rows of wells are brought on production and injection. Other applications of well testing are given including analyzing the effectiveness of fracturing, and detecting distortion of casing in a water injection well. An example is given of using well tests to evaluate the effectiveness of a lime suspension treatment to plug a large channel. Examples are also provided of how interference tests were used in conjunction with tracer testing to evaluate inter-well communication and fracture direction.
The Logging Technology for Determining Production Profiles Through Casing/Tubing Annulus in Pumping Wells
Authors: Zhang Baoqun , Zhang Shuying , Wang Baochun , Zhang Weiping 
Published: June 2014

Abstract
Logging technology for determining production profiles through casing/tubing, the small diameterseries of designing tools, and the advanced logging techniques is described. Applications of the logging technology are demonstrated using typical examples.
Experimental Investigation on the Dielectric Constant of Rocks with Low Porosity and Permeability
Authors: Weinan Wang , Xi Zhang , Xiuwen Geng , Qingzhen Chang 
Published: June 2014

Abstract
Relation between the dielectric constant of rocks, sampled from the western exploring area of Daqing Oil Field, and water saturation, salinity is developed. Effect of shale and water distribution on the dielectric constant is discussed through experiments on artificial core samples and shale samples. The mixing law that describes the relation between dielectric constant and water saturation is revised and a new one characterized by the area is proposed.
The Logging Technology for Determining Water-Intake Profile With the Radioisotopic Carriers
Authors: Niu Chaoqun , Qiao Hetang , Chen Shiduo , Chen Xiaohua 
Published: June 2014

Abstract
The logging technology of radioisotopic carriers has long been a main means to monitor and survey injection profiles in during water injection. This paper focuses on the basic principles of the logging technology, radioisotopic microballs, logging tools, auxiliary equipment, logging techniques, data interpretation, and application effects.
Methods and Effects of Cyclic Waterflooding in the Southern Oilfields of Daqing Placanticline
Authors: Zhongrong Li , Xianzhi Shao , Yongsong Qiu , Xuezhong Chen 
Published: June 2014

Abstract
The paper summarizes the methods and effects of cyclic waterflooding in the southern oilfields of the Daqing Placanticline, discusses the feasibility and necessity of this process in lower permeability reservoirs, and analyzes systematically the main factors which impact the results of cyclic flooding. Production performance is compared and contrasted for fields developed by both conventional, and cyclic waterflooding. Based on field case histories, the impact of cyclic waterflooding on performance at different water cuts is evaluated. It is demonstrated that cyclic flooding should be implemented at low water cuts, but is beneficial at all development stages. Cyclic waterflooding is an effective measure to enlarge sweep volume and enhance conformance efficiency and oil recovery. The practices described can provide guidance for cyclic waterflooding in similar oilfields.
Major Technical Measures To Increase The Recoverable Reserves Of Large Heterogeneous Sandstone Oil Fields
Authors: Demin Wang , Chengzao Jiang , Yingjie Sun 
Published: June 2014

Abstract
Daqing Oil Field is the largest oil field in China and one of the largest oil fields in the world. Development began 35 years ago. By cyclic identification and comparison of continental heterogeneous sandstones, studies on sedimentation models and sand body types, a better understanding of the development stage, water flood characteristics and residual oil distribution of different types of sandstones was obtained. A whole set of technologies (including geology, reservoir engineering, drilling, production, open hole logging and production logging) were developed to increase the recoverable reserves of different zones. As a result, at each stage of development the recoverable reserves of the oil field were increased. It is estimated that after drilling the third round of infill wells and after polymer flooding, the recoverable reserves will be 118 to 133% higher than 1978. Daqing was brought on production in 1960. The present water cut is around 80%. Production reached 50 × 106t in 1976 and in 1995 reached a record high of 56 × 106. Production has been stable for 20 years and is estimated to be stable for another long period of time. Excellent development results have been obtained and are better than planned.
Planning a Dynamic Kill
Authors: Abel L. William 
Published: June 2014

Summary
This article discusses the methodology, design philosophy, and guidelines for planning a dynamic-kill operation for a wild well. The topics covered are two methods of computer analysis for designing dynamic-kill requirements, the design process, determining the pumping spread, and the pitfalls that a designer faces in planning a dynamic kill.

Introduction
The dynamic kill of a blowout involves pumping fluid through a conduit (a relief well, snubbing string, or drillstem) to stop the blowout and kill the well. Fig. 1 shows a typical scenario for a relief well. While dynamic kills are sometimes accomplished by pumping down a conduit that is in or snubbed into the well, this application is limited because the bore of the conduit restricts the pumping rate. In a dynamic kill, the blowout well is overcome by the combination of increased hydrostatic and frictional pressures in the wellbore. A common misconception is that the friction component is the major factor. Field results and computer models that account for two-phase flow show that the blowout well can be killed more readily by introducing a high-density fluid into the wellbore instead of pumping at high rates to generate frictional-pressure losses. Therefore, the most cost-effective dynamic-kill solution will generally involve pumping dense mud rather than water or other low-density fluids.
The kill fluid and pumping design must account for many factors, including leakoff, formation fracturing, and reservoir parameters. Many times, these values contain uncertainties that must be dealt with in the analysis. However, the single most important factor is the increase in hydrostatic pressure during the initial kill operations. This occurs as the kill fluid mixes with the blowout effluent and increases hydrostatic pressure in the wellbore. The only exception is the underground blowout. In some underground blowouts a reactive material that generates high frictional pressures can be used to generate a "friction" kill instead of a hydrostatic kill. This is true under only a very limited number of underground blowout conditions.
Depletion Performance of Gas-Condensate Reservoirs
Authors: Raghavan Rajagopal , Jones Jack R. 
Published: June 2014

Distinguished Author Series articles are general, descriptive representations that summarize the state of the art in an area of technology by describing recent developments for readers who are not specialists in the topics discussed. Written by individuals recognized as experts in the area, these articles provide key references to more definitive work and present specific details only to illustrate the technology. Purpose: to inform the general readership of recent advances in various areas of petroleum engineering.

Introduction
This paper reviews basic methods for evaluating the depletion performance of a well producing a gas-condensate fluid. In particular, we discuss initial gas-in-place estimates, inflow-performance relationships, the development and behavior of liquid saturations over both time and drainage area, and the interpretation of pressure-transient tests. Every aspect of these calculations for depletion of a gas-condensate, or any other essentially two-phase system, is implicitly dictated by the interaction between the fluid properties of the initial gas-in-place and the relative permeability properties of the reservoir rock. The simple steady-state theory forms a useful framework for understanding these interactions and often yields practical approximations for some important quantities. This theory and its relationship to commonly available laboratory measurements form the foundation for many of the methods discussed.

Fluid Determination, Properties, and Descriptions
Classification of a reservoir fluid as a black oil, volatile oil, gas condensate, wet gas, or dry gas is important because application of appropriate engineering practices to predict reserves and rates traditionally requires this knowledge. Fig. 1 is a schematic of a pressure/temperature (p-T) diagram for a multicomponent hydrocarbon mixture of constant composition. The region inside the envelope formed by the bubblepoint curve, critical point (C), and dewpoint curve is where liquid and vapor exist in equilibrium. Lines of constant liquid volume are shown inside this region. Fluids initially at temperature and pressure Positions I through V would be classified as a black oil, volatile oil, gas condensate, wet gas, and dry gas, respectively. Gas condensates are separated from the other fluid types by two characteristics: the condensation of a liquid phase at reservoir conditions during isothermal depletion and the retrograde (revaporization) nature of this condensation. Retrograde behavior of the condensing liquid phase can be seen by tracing the change in liquid volume along the constant-temperature line beginning at Point M in Fig. 1. After crossing the dewpoint line, the volume of liquid increases to approximately 10%at Point N and then begins to decrease with continued reduction in pressure.
X-Ray Computer-Assisted Tomography for Laboratory Core Studies
Authors: Hicks Paul J. 
Published: June 2014

Introduction
X-ray computer-assisted tomography (CT) entered the petroleum scene about 13 years ago. The technology showed much promise, but was expensive, unproven, and inaccessible to most petroleum engineers. Today CT scanners are an integral part of most major oil company, service company, and research university laboratories. This paper gives an overview of the theory and typical applications of CT.

Theory
Although CT is used to determine a wide variety of oilfield rock and fluid properties, it measures only one property, the linear attenuation coefficient, µ. The linear attenuation coefficient is defined by Beer's law and is a measure of the fraction of X -rays that pass through an object.

Applications
CT measurements are nondestructive and relatively fast. Most petroleum applications are aimed at estimating lithology, porosity, and/or saturation. By conducting well-designed experiments, these three parameters can be used to obtain a wide variety of additional information. When plugs are to be taken from whole cores, the whole core can be scanned beforehand, enabling the plugs to be taken at appropriate locations. This can be done without removing the wrappings for preserved cores.
Lithology and Porosity. Lithology determination is typically performed for one of two reasons. The first is the screening of cores. Cores are used in a wide variety of laboratory flooding experiments. Even if CT is not used during the flow experiments, it is a useful tool for selecting cores for these experiments. Flooding experiments can be expensive and time consuming, and their analysis typically involves an assumption of uniform porosity and/or permeability. Little is more disheartening than spending months on a project only to find that your analysis is suspect or wrong because a supposedly homogeneous core has a significant interior shale streak or other heterogeneity, unnoticed from the outside. Today, many samples are routinely CT scanned to check qualitatively for homogeneity before conducting coreflooding experiments. This should be standard procedure.
Design and Installation of a Cost Effective Completion System for Horizontal Chalk Wells Where Multiple Zones Require Acid Stimulation
Authors: Thomson D. W. , Nazroo M. F. 
Published: June 2014

Abstract
An innovative completion design that allows multiple acid fracs to be performed in horizontal subsea chalk-formation wells with a single trip into the wellbore has recently been codeveloped by a major North Sea operator and an oilfield engineering/manufac-turing/service company. The project was initiated to develop a system that would allow multiple acid stimulations to be efficiently performed in the shortest possible time in the North Sea Joanne Field. The system ultimately developed allows acid stimulation of up to 10 different zones in a single trip with no through-tubing intervention. The first well in which this new technique was used had 7 zones, and 3 additional wells with 10 zones each were later completed. The development of this system and case histories of the first four subsea wells requiring stimulation will be presented in the paper.
The key element of the system is a multi-stage acid frac tool (MSAF) that is similar to a sliding sleeve circulating device and is run in the closed position. Up to 9 MSAF tools can be run in the completion with isolation of each zone being achieved by hydraulic-set retrievable packers that are positioned on each side of an MSAF tool. Each sleeve contains a threaded ball seat with the smallest ball seat in the lowest sleeve and the largest ball seat in the highest sleeve. With this system, stimulation of 10 separate zones is accomplished in 12-18 hours by a unique procedure that lubricates varying sized low-specific gravity balls into the tubing and then pumps them to a mating seat in the appropriate MSAF, thus sealing off the stimulated zone and allowing stimulation of the next zone which is made accessible by opening the sleeve.
This technique provided a substantial reduction in the operational time normally required to stimulate multiple zones and allowed the stimulations to be precisely targeted within the reservoir. The case history data will provide comparisons in operational times between traditional stimulations and this new method as well as the significant enhancements to cost efficiency that resulted from its use. Additionally, this completion method allowed the stimulations to be designed and matched to the requirements of each reservoir zone, which provided the most cost efficient treatments possible.