bluuebunny/crossref_metadata_2025_split huggingface dataset:
Negative Alkalinity Invert Emulsion Drilling Fluid Extends the Utility of Ester-Based Fluids
Authors: Patel Arvind D. 
Published: December 2007

Abstract
Biodegradability of drilling-fluid chemicals is becoming a requirement for discharge of drilled cuttings on offshore drilling operations, especially in Europe. Due to their ready biodegradability, fatty acid esters are very popular in the North Sea. While esters enjoy advantages over other synthetic-based fluids on the biodegradability issue, their drilling fluid performance has remained substandard. The ester-based fluids undergo hydrolysis in the presence of lime at temperatures exceeding 200°F (93°C).
A new approach to the stability of ester-based fluids is a new, negative-alkalinity ester-based drilling fluid that is stable up to 350°F (177°C). The thermal stability and performance characteristics of the negative alkalinity ester-based drilling fluids are superior to the conventional ester-based mud formulations. The system uses a surfactant package that is designed to perform as an invert emulsifier under negative alkalinity conditions. The negative alkalinity ester-based drilling fluid system is simple and easy to run without any exotic change in the chemistry of esters. The system can be formulated using relativity inexpensive and readily available fatty acid esters. Due to the enhanced stability of fatty acid esters in this system, the selection of the esters utilized in this system can be based on economic considerations and availability rather than hydrolytic stability of the ester base fluid.
The thermal stability and performance characteristics of the negative-alkalinity ester-based drilling fluid are presented in this paper. A comparison of stability of the various types of ester base fluids using negative alkalinity invert emulsion and conventional reserve alkalinity ester-based drilling fluid shows that the negative alkalinity ester-based drilling fluids are stable up to 350°F (177°C). The paper discusses the overall impact of negative alkalinity ester-based drilling fluid in meeting the environmental and functional requirements of drilling operations and the economic advantages derived from this innovative system.
The Alba Field Ocean Bottom Cable Seismic Survey: Impact on Development
Authors: MacLeod M. K , Hanson R. A. , Bell C. R. , McHugo S. 
Published: December 2007

Abstract
In early 1998, Chevron acquired one of the world's first full-field four-component ocean bottom cable (3D/4C OBC) surveys at the Alba field in the central UK North Sea. The primary objective of the survey was to use converted shear waves to provide a better image of the sandstone reservoir and shales within the reservoir. Pre-survey technical studies based on a dipole sonic log and 2D OBC seismic lines gave us confidence that converted waves (PS) could provide a better image of the reservoir relative to conventional P-wave seismic data.
The secondary objective of the new survey was to map water movement in the reservoir after four years of production and water injection by comparing the new P-wave OBC data with the original 1989 streamer data. A strong original oil-water contact reflector seen throughout much of the field and pre-survey technical studies suggested that production-related saturation changes would be observable on the new P-wave OBC seismic data.
The new data shows that both objectives were achieved with dramatic results - the converted-wave images provide the clearest image of the Alba reservoir sands ever seen and production effects are obvious on the new P-wave OBC data near several producing and injector wells. In addition, the converted-wave data has offered new insights into the shape of the reservoir. The previous lens-shaped interpretation based on P-wave data has been replaced with a far more complex shape that is at least in part related to post-depositional structural alteration. This new interpretation is also supported by improved reservoir images seen on far-offset P-wave sections.
To date, two successful wells have been drilled based primarily on the converted-wave seismic data. Both wells prove the existence of ‘wings’ – structurally high sand at the margins of the channel that may represent re-mobilized and injected reservoir sand. Neither of these wings had been previously identified on the conventional P-wave streamer seismic data.
Designing Teams for Safety, Productivity, and Job Satisfaction: Recent Research and Operator Experience
Authors: Everest P. , Lardner R. , Turek M. 
Published: December 2007

Abstract
One of the most cost-effective methods of work organisation for manufacturing industry is self-managing teams (SMTs). SMTs have an established track record of improving productivity, job satisfaction and employee involvement. There has been a recent trend for onshore and offshore petrochemicals and process industry operators to implement SMTs. A fundamental aspect of SMTs is devolving day-to-day responsibility and decision-making to employees, and reducing or eliminating the role of the first-line supervisor. However, the suitability of SMTs for safety-critical operations has been questioned, and anecdotal evidence exists of flawed implementation and lapses in safety.
This paper summarises the results of (a) a joint industry project, funded by the UK Health and Safety Executive (Offshore Safety Division) and BP Oil, which examined the safety implications of self-managed teams and (b) operator experience of SMT implementation on BP's Miller Field from 1995 to date.
Planning for the post-plateau years of the Miller platform in the North Sea truly commenced whilst the installation was still in the blocks in Newcastle. However, detailed research for the shape of an offshore organisation that would see the facilities into anticipated post-plateau and other, then unknown, challenges, commenced in 1995. Implementation of a project to install SMTs commenced in 1996 and since that time considerable progress has been made in developing the practical application of self-managing teams in an offshore environment. The platform management team may claim only modest success with SMTs, but in reality the project has delivered considerable revenue savings to the Miller business and above all has made a significant contribution to the HSE programme for the business. Our belief is that through SMTs Miller will be enabled to deliver exemplary business, and especially, exemplary HSE performance.
Balanced Approach to Health and Safety Management
Authors: Bell Eric R. G. 
Published: December 2007

Abstract
Conoco (U.K.) Limited (CUKL) has a proud history of achievement in its approach to Health and Safety management. Our motto, Our work is never so urgent or important that we cannot take time to do it safely, fosters a principled approach to safety management and has served us well for many years.
The continuing challenge is to ensure that the organisation does not become complacent in respect of safety management. Whilst strong leadership and management commitment are critical in the achievement of a safe performance, they represent only one measure of success. Conoco believes that the key to excellence in this area is the enrolment of the entire workforce; the employees and contractor personnel alike who are engaged in the work of the company thus creating a balanced approach to Health and Safety management.
This paper will describe clearly the action taken, primarily since the beginning of 1997, in achieving the balanced approach while considering the consequent effect on safety performance.
Stochastic Inversion for High Resolution Reservoir Characterisation in the Central Sumatra Basin
Authors: Sams M. S. , Atkins D. , Said N. , Parwito E. , van Riel P. 
Published: December 2007

Abstract
High resolution models of complex reservoirs can be obtained through stochastic inversion combined with lithology simulation. The models are constrained by the requirement to honour all seismic, log and geologic input data. Generation of multiple models fulfilling this requirement permits the uncertainties to be quantified. Model realisations at high resolution mean that the properties of individual reservoir units that are not resolved by conventional seismic reflection imaging techniques can be investigated.
Stochastic inversion with lithology simulation is a powerful tool for integrating a wide variety of data - geological, geophysical, petrophysical and statistical - to produce constrained, detailed models of reservoirs. These models can be used for static or dynamic modelling. The technique is well suited to mature fields such as those in the Central Sumatra Basin, where the objectives are to find bypassed reserves and optimise well planning for secondary or tertiary recovery.
A case study from the Libo SE field of the Central Sumatra Basin is presented. Deterministic inversion of the seismic data could not resolve all the sand units of interest in the complex reservoir of this field. Stochastic inversion with lithology simulation resulted in reservoir models from which the distribution and properties of the individual sand units could be predicted. The high quality of these models was confirmed by the results from recent drilling.
Locating Remaining Reserves Using Inside Tubing PNS Logging
Authors: Njoku Chima 
Published: December 2007

Abstract
In the Brunei deltaic environment, prediction of present fluid contacts from simulation models is difficult. Presence of sub-seismic faults as well as cross flows between reservoirs have been established in some cases. It is thus important to explore other cost-effective methods to confirm or locate by-passed/undrained reserves before embarking on any new perforations or in-fill well drilling. One such method is inside tubing pulsed neutron spectrometry (IT-PNS) logging.
IT-PNS logging entails logging slim PNS tools inside the long/single string with the well closed in more than two days before the logging. One pass in the SIGMA mode for gas detection and multiple passes in inelastic mode for oil "saturation" are logged.
The first (trial) IT-PNS well was logged in August 1998 and since then, as many as thirteen Brunei Darussalam wells have been logged using this technique. Results show that: (i) the technique can be successfully used to determine present formation fluid types, even in low porosity/permeability reservoirs. (ii) there is no need to use a rig for fluid contact measurement. (iii) in static conditions, the annular fluid type will have little or no impact on the final interpretation. (iv) three to four inelastic passes are adequate for interpretation of the liquid phase. (v) by-passed reserves have been located using the technique, thus reducing the risk of drilling dry holes.
An Alkaline Bio-Surfactant Polymer Flooding Pilots in Daqing Oil Field
Authors: Demin Wang , Jiecheng Cheng , Qun Li , Lizhong Li , Changjiu Zhao 
Published: December 2007

Abstract
After studying zones, geological sediments, oil and water, etc. of different characteristics, an Alkaline-Surfactant-Polymer flooding formulation mainly with alkylbenzene sulfonate was screened. Pilot investigation with this formulation has been conducted with different alkali and different zones, good results have been achieved both technically and economically.[1,2]
Based on former study results,[3,4] screening of ASP formulations to further reduce the usage of surfactants and get better technical and economical results were performed. The interfacial tension behavior between oil and bio-surfactant ASP systems, emulsion characteristics, adsorption, core flooding, as well as numerical simulation, etc. were studied. After success in the laboratory study, the first Alkaline Bio-Surfactant Polymer Flooding Pilot was conducted in the north of the oil field.
Both laboratory and pilot studies showed that the Alkaline Bio-Surfactant Polymer Flooding system not only can further reduce the usage of surfactant and dynamic adsorption, but also can further reduce the ultra-low interfacial tension, extend the ultra-low interfacial tension area. Its emulsion phenomenon and chromatographic separation was not significant. After the implementation of the Alkaline Bio-Surfactant Polymer Flooding pilot, good results in terms of daily water cut decrease and incremental oil of the central well were obtained, the actual production data was better than the numerical simulation prediction.
Now, the oil recovery of the central area is 21.5% OOIP over that of water flooding, preliminary economic analyses show that the chemical cost per ton of incremental oil is less than 30$. This should be a good bio-chemical flooding method.
The 3-D Architecture of Point Bar and The Forming and Distribution of Remaining oil
Authors: Ma Shizhong , Zhang Jing , Jin Ningde , Wang Zaishan , Wang Yuming 
Published: December 2007

Abstract
It has generally been considered that remaining oil forming in vertical is mainly controlled by permeability succession, the important effects of very thin lateral accretion mudstone (LAM) interbeds and permeability subsuccession have been neglected. By analyzing the sedimentary processes and efficiency of displacement oil (EDO) of point bar in P I 2 time unit, Daqing oilfield, point out that the 3-D architecture of point bar is the key of the forming and distribution of remaining oil (FDRO) and that many lunate-shape, oblique, very thin (&lt;20cm thickness) LAMs in point bar are the most important barrier beds and permeability control-framework, and that lateral accretion sandstone body (LAS) is the basic and important unit of controlling spatial distribution of permeability in point bar, and set up the "3-D architecture of LAM+LAS+fluid density difference" model of FDRO.
A Technology of Soaking and Discharging CO2 to Enhance Production in Binnan Tract
Authors: Zhigang Wang , Shijun Fan , Guilin Zhu , Zenghai Ma , Jinfa Li 
Published: December 2007

Abstract
In Binnan Tract of Shengli Oilfield, there is sufficient CO2 in the reservoirs and there are much reserves suitable to take the measure of soaking and discharging CO2 to enhance production. In this paper, laboratory experiments and field tests have been conducted pertaining to this technology, and the results indicate that under the pressure of 25MPa, CO2 can mix with oil well. Then, the recovery efficiency of residual oil by water drive can increase 10%. The results of numerical simulation show that optimized effect can be reached through regulating the volume of CO2, duration of soaking, injecting and discharging velocity, while the production will decrease in the second stage compared to the first one. The processes of reverse injection, corrosion and expansion prevention, were taken in the field test, which input-output ratio was as high as 1:4.22, proving that this technology is viable in small lower-permeability reservoirs.
Gas Lift Optimization Efforts and Challenges
Authors: Chia Y. C. , Hussain Sies 
Published: December 2007

AbstractGas lift plays an important role in Esso Production Malaysia Inc. (EPMI) oil production operation. As oil fields mature, the production facilities need to handle increasing water and gas. Gas lift optimization is crucial to ensure maximum oil production within facility constraints. Nodal analysis, Gas lift Optimization Allocation model (GOAL), gas lift databases and Gas Lift Monitoring System (GLMS) are among the tools applied to meet the objective. Some of the challenges encountered during the gas lift optimization efforts are dual gas lift optimization, tight dummy valve retrieval at one particular platform, production from thin oil column, emulsion and sand production.
Study on Genetic Type and Potential Tapping Measures of the Remaining Oil in Multilayered and Heterogeneous Sandstone Reservoir
Authors: Qinglong Du , Yongsheng Zhao , Yinyin Lu , Liting Zhu 
Published: December 2007

Abstract
The various influential factors for remaining oil space distribution are discussed on geological and productive basis. Genetic types of areal and vertical remaining oil are summarized while corresponding potential tapping measures for remaining oil with different genetic types are put forward by combining production technologies and means. Several examples are presented here for their success in tapping the potential of remaining oil at the late period of high water cut stage in Daqing Oilfield.
Emerged Horizontal Drilling Technology and Its Applications in Saudi Oil Fields in The Last Ten Years
Authors: Al-Blehed M. S. , Hamada G. M. 
Published: December 2007

Abstract
The technology of drilling and production of horizontal wells is probably one of the most significant breakthrough in the oil and gas industry of the eighties. What was considered ten years ago, as an exotic way of drilling has become reality. The continuous improvement of hardware equipment made horizontal drilling cost-effective technique for developing reserves, improving productivity and recovery in oil and gas reservoir.
Horizontal well technology continues to be at the forefront of the oil industry. This paper will highlight the Saudi experience in horizontal drilling. The past ten years have been an exciting period for those who believed in horizontal drilling applicability in Saudi Arabia. At the end of the year 1997 over than 150 horizontal wells have been drilled in Saudi oil fields. There are four major horizontal well applications identified in Saudi Arabia oil fields; 1) Control of coning in relatively thin remaining oil column area, 2) Improving sweep efficiency of water flooding program, 3) Improving productivity rate in thin/tight reservoirs and 4) Saving in total development costs in conjunction with previous three applications.
This paper presents the major areas of application of horizontal wells and more specifically the objectives of applying horizontal drilling in different Saudi oil fields. In this paper, the world horizontal drilling activities along with the Saudi experience will be covered. This paper surveys different field examples to show the application trends of horizontal well technology in both offshore and onshore oil fields. The main objective of this survey is to demonstrate the performance improvement of these oil fields after the application of horizontal well technology.
Relative Permeability Ideas-Then and Now (Richards to Leverett to Yuster, and Beyond)
Authors: Rose Walter 
Published: December 2007

ABSTRACT
Here in an Appendix are some paraphrases with updated annotations are presented of the Author's changing ideas over the years about relative permeability phenomena. These have been contained in a series of publications from 1948 to date, however not always in a concordant way. In point of fact, some initially were chosen to be consistent merely with empirical information. More recently, however, the papers have tended to be based on the prescripts of non-equilibrium thermodynamics.
In one way or another, and indeed now for almost a Century, the voluminous literature on the subject has substantially been influenced by the evolving understandings about the meanings and applicability of what today still remains to be a perplexing (rather than an ubiquitous) relative permeability concept. Some might say (but others, not) that this very subject already has been sufficiently dealt with by generations of previous authorities. Outstanding ones to be mentioned here are Richards (1931), Leverett (1942), and Yuster (1951), but passing reference also will be made to the remarkable achievements of other gigantic innovators. Any mention a few of them would surely include the works of Edgar Buckingham (1907), Josef Kozeny (1927), M. King Hubbert (1935 and 1956), P. C. Carman (1937), G. L. Hassler (1944), Morris Muskat (1937 and 1949), J. R. Philip (1955) to date, A. E. Scheidegger (1957 as revised in 1974), M. R. J. Wyllie (1962), E. C. Childs (1969), Jacob Bear (1972) to date, Francois Kalaydjian in the 1980s and 1990s, and Steve Whitaker et al (1986 et.seq.). Even so, the simple aim held by the Author of the present paper is to show that further clarifications still are urgently needed. And the focus of major importance now should have to do with how best to measure and to apply relative permeability data whenever simulation studies of reservoir transport processes are to be undertaken.
Effects of Coalbed Reservoir Property Analysis Methods on Gas-In-Place Estimates
Authors: Nelson Charles R. 
Published: December 2007

Abstract
Accurately determining the gas-in-place volume is a crucial element of coalbed gas resource and reservoir evaluation. Different reservoir property analysis methods can yield very different gas resource and gas-in-place values. This paper presents results from evaluations of the accuracy of commonly used reservoir property analysis methods. Many commonly used analysis methods were found to have inherent shortcomings that can result in large (50% or greater) underestimation error in the gas-in-place value. Six major sources of error are: (1) basing the reservoir volume on the assumption that the coalbed reservoir thickness and lateral continuity are invariant, (2) using 1.75 g/cm3 as the maximum log density value for determining the gross reservoir thickness, (3) using 1.32 to 1.36 g/cm3 for the in-situ density of coalbed reservoirs, (4) basing the in-situ gas content on gas desorption data obtained at ambient temperature conditions, (5) basing the in-situ gas content on gas desorption data obtained from drill cuttings, and (6) basing the in-situ gas content on the assumption that the residual gas volume is negligible. Because these six error prone analysis practices have been so widely used in the past there may be significant potential for large gas-in-place and reserve estimate gains in many existing coalbed gas fields.
Case History: Automation System Increases Production and Enhances Well Safety in the Ramos Gas Field In Argentina
Authors: Reyes Alfonso , Plunkett Joe , Teja Ricardo , Zambrano Oscar 
Published: December 2007

Abstract
The automation of the high-production Ramos gas field, located in the northern region of Argentina, has enhanced field production and well safety and also improved operations by centralizing control of the gas production. A field supervisory control and data acquisition (SCADA) computer located in a gas treatment plant automates the gas production throughout the field by means of a radio telemetry link to a well control unit (WCU) that is located at each automated well site. From the plant, operations personnel can change the production rate or monitor production variables at any wellsite, view real-time or historical trends of those variables, or change alarm setpoints in a WCU from graphical screens on a computer console. The computer archives the production data onto a hard disk for further processing and analysis.
A solar-powered WCU located at each site controls well production by means of an electrically activated choke mounted on the wellhead. The WCU, a microprocessor-based controller, monitors operating pressures, temperatures and tank levels, and it ensures well and flow-line safety by controlling the operation of the surface safety valve (SSV) and the sub-surface safety valve (SSSV).
Currently, the automation system involves nine wells. Early in 2000, three additional wells will be automated.