bluuebunny/crossref_metadata_2025_split huggingface dataset:
Environmental Aspects of the Use and Disposal of Non Aqueous Drilling Fluids Associated with Offshore Oil & Gas Operations
Authors: Melton H. R. , Smith J. P. , Mairs H. L. , Bernier R. F. , Garland E. , Glickman A. H. , Jones F. V. , Ray J. P. , Thomas D. , Campbell J. A. 
Published: December 2007

Abstract
High-performance non-aqueous drilling fluids (NADFs) are required to meet the challenging technical requirements of many offshore wells. Significant advances have led to the development of advanced NADFs, such as paraffins, olefins and esters, that are less toxic and more biodegradable than early generation diesel and mineral oil base fluids. Advanced NADFs provide the necessary drilling performance while ensuring environmentally-sound operations.
Three options exist to manage waste from NADF-coated drill cuttings: marine discharge, downhole injection, and hauling to shore for land disposal. All options have advantages and disadvantages with regard to total life cycle environmental impact, safety, cost, and operational performance. Marine discharge of cuttings associated with advanced NADFs, however, is the option with the highest safety and operational flexibility. Further, the improved environmental performance of advanced NADFs broadens the acceptability of marine discharge.
Field monitoring studies at multiple offshore drilling sites reveal a relatively consistent picture of the fate and effects of discharging drill cuttings associated with NADFs. The degree of impact is a function of local environmental conditions (water depth, currents, temperature), the amount of material discharged, and the type of drilling fluid used. More significant temporal and spatial effects were observed at sites that used early generation drilling fluids. Wells drilled with advanced NADFs resulted in smaller zones of seafloor impact and more rapid recovery of the benthic communities.
This paper, based on the work performed by a task force of the International association of Oil and Gas Producers (OGP)&lt;sup&gt;1&lt;/sup&gt;, summarizes our knowledge base of the environmental-effects related to the discharge of NADF-coated drill cuttings. In addition, it describes tools and techniques for assessing environmental effects including laboratory methods to determine drilling fluid toxicity, biodegradability, and bioaccumulation potential and numerical models to predict the seafloor distribution of cuttings.
The paper is intended to aid regulatory development and project environmental assessments by providing information to help balance environmental, operational, and cost considerations when choosing waste-management options for NADF drilling.
Tackling Road Safety In a Global Upstream Business: An Integrated and Long Term Approach
Authors: Malone Charles 
Published: December 2007

Abstract
In a global upstream company effectively managed road transport is a vital component to the success of an operation. If it is not managed effectively the consequences when things go wrong are severe and can ultimately lead to loss of human life, which is intolerable. This paper explains the integrated approach that Shell Exploration and Production is currently embarking on to tackle road safety globally for the long term.
The Future of the Petroleum Industry in California and Louisiana
Authors: Cook P.G. 
Published: December 2007

Abstract
The demand for crude oil in California and Louisiana, respectively, by 1967, is anticipated to approximate 700 million bbl and 600 million bbl annually. Natural gas consumption in California is anticipated to rise to 3.0 billion Mcf annually which will require the importing of some 2.4 billion Mcf to supplement production. The total consumption of natural gas in Louisiana is anticipated to increase to 1.6 billion Mcf and leave about 2.9 to 4.5 billion Mcf for exportation.
The anticipated drilling activity in California is anticipated to increase to 2,440 walls annually and then decline to 2,260 wells annually by 1967. In Louisiana, the number of wells drilled annually may reach 7,000. The total footage drilled annually and the average well depth will increase in both states.
The anticipated California total capacity to produce will decline to 28 B/D/well by 1958, while in Louisiana the anticipated capacity to produce will be around 53 B/D/well. Primary production of crude oil will decline in California to an anticipated 310 million bbl annually and in Louisiana production will increase to 660 million bbl. It is thought that natural gas production will decline to 535 million Mcf in California and in Louisiana it will increase to a value of 4.5 billion Mcf.
The production - discovery ratio for California is anticipated to climb to 5 to 1, and over the projected time 1.5 billion bbl of new oil will be discovered, yet the reserves are anticipated to decline to about 2.2 billion bbl. The natural gas reserves are anticipated to decline to about 3.62 billion Mcf. Offshore crude oil and natural gas reserves are estimated at a maximum of 4.0 billion and 9 to 10 billion Mcf. Present Louisiana onshore crude oil reserves are indicated to be 7.1 billion bbl. Offshore reserves are estimated at 12 billion bbl of crude oil and about 100 billion Mcf of natural gas.
A summation of various crude oil production curves indicate that California peak production may not occur until 1965 and could well attain a value of 380 million bbl annually. At the anticipated rate, peak production in Louisiana may occur in 1975 with a possible value of 730 million bbl annually.
3D Geological Modeling of a Carbonate Reservoir, Utilizing Open-Hole Log Response – Porosity & Permeability – Lithofacies Relationship
Authors: Akatsuka K. 
Published: December 2007

Abstract
A lithofacies based reservoir characterization study was conducted for a Lower Cretaceous carbonate reservoir in order to build a numerical 3-dimensional geological model including permeability prediction and rock typing for reservoir flow simulation.
This paper describes a procedure for constructing a lithofacies based geological model for reservoir flow simulation. This is the first time a lithofacies based reservoir characterization has been applied to the target reservoir. We believe this model is a reasonable representation of the reservoir as it gave a good match between predicted permeability and well test permeability.
Nine lithofacies were identified from detailed slabbed core observations and lithofacies of non-cored wells were predicted from the cross plots between DT, RHOB, PHIE and MSFL of each lithofacies.
The relationship between lithofacies and open-hole log response was also effective in estimating the spatial distribution of each lithofacies. A lithofacies trend map, which shows the lateral variation of lithofacies, was produced by applying this relationship to maps of vertically averaged log response. A lithofacies distribution map was prepared by incorporating a geological interpretation of thickness and porosity variations into the trend map.
Horizontal permeability was predicted from simple core porosity-permeability regressions for each lithofacies using log porosity as the input. Using the lithofacies distribution map and the relationship between porosity and permeability of each lithofacies, the lateral variation of horizontal permeability was predicted without direct interpolation or extrapolation of permeability data between wells. The general trend of this modeled permeability was similar to the permeability derived from production tests. However, the absolute value of modeled permeability was lower than the well test permeability across the reservoir. This phenomenon might be due to the existence of high permeability streaks which were not cored.
Investigation of the relationship between lithofacies and petrophysical data, such as special core analysis, was carried out based on pore throat size distribution curves derived from capillary pressure data. As a result, four rock types were identified in the reservoir.
Predictive Modelling of Naturally Fractured Reservoirs Using Geomechanics and Flow Simulation
Authors: Bourne Stephen J. , Brauckmann Franz , Rijkels Lex , Stephenson Ben J. , Weber Alex , Willemse Emanuel J. M. 
Published: December 2007

Abstract
To optimise recovery in naturally fractured reservoirs, the field-scale distribution of fracture properties must be understood and quantified. We present a semi-deterministic method to systematically predict the spatial distribution of natural fractures and their effect on flow simulations. This approach enables the calculation of field-scale fracture models. These are calibrated by geological, well test and field production data to constrain the distributions of fractures within the inter-well space.
First, we calculate the stress distribution at the time of fracturing using the present-day structural reservoir geometry. This calculation is based on geomechanical models of rock deformation such as elastic faulting. Second, the calculated stress field is used to govern the simulated growth of fracture networks. Finally, the fractures are upscaled dynamically by simulating flow through the discrete fracture network per grid block, enabling field-scale multi-phase reservoir simulation. Uncertainties associated with these predictions are considerably reduced by constraining and validating the models with seismic, borehole, well test and production data.
This approach is able to predict physically and geologically realistic fracture networks. Its successful application to outcrops and reservoirs demonstrates there is a high degree of predictability in the properties of natural fracture networks. Several examples show the success of the method in single- and multi-phase fields. In cases of limited data – where stochastic models typically fail – this method remains robust.
Full Field Reservoir Simulation Study of an Oil Rim in a Field Offshore Abu Dhabi (UAE)
Authors: Decroux Bruno , El Emam Medhat , Nassar Omar , Kadada Talal , Karakhanian Hagop 
Published: December 2007

Abstract
This paper presents a case study drawn from a full field simulation study on an oil rim in a field offshore Abu Dhabi.
Initially the reservoir contained a large gas cap underlain by a thin saturated oil rim. The gas production from the gas cap started in 1976. In 1989, about 22% of the gas from the gas cap had been produced. The reservoir pressure had dropped by more than 1100 psi. Then gas injection from a deeper reservoir into the gas cap started and the reservoir was slowly repressurised. However, a moderately active aquifer encroached and flooded part of the oil rim. The oil was pushed up dip.
The main objective of the study was to propose a full field development scheme for the oil rim. Meanwhile, the opportunity was taken to optimise the condensate recovery.
A multidisciplinary reservoir characterisation study was carried out on the formation. Based on this study, seven rock types were defined and a reservoir-layering scheme was developed. A full field compositional simulation model was built and history matched. The history match included the match of six oil producers, which experienced water and/or free gas production. The Gas Cap CGR history was also successfully matched.
Finally, the history-matched model was used for recommending a development scenario. Few oil producer concepts were tested. Several development scenarios were compared. One of the scenarios was assuming gas cap depletion after year 2005 while the other scenarios were assuming partial or full recycling at different rates.
Optimization of Process Parameters for Glycol Unit to Mitigate the Emission of BTEX/VOCs
Authors: Braek A. M. , Almehaideb R. A. , Darwish N. , Hughes R. 
Published: December 2007

Abstract
Recent developments in environmental regulations have made emissions of the aromatic compounds Benzene, Toluene, Ethyl-Benzene, and Xylene isomers (BTEX) and other Volatile Organic Compounds (VOCs) from glycol units a major concern for the natural gas industry. Hence, quantifying the absorption levels has become more important in recent years due to increased restrictions on BTEX/VOC Emissions from glycol dehydration units.
This problem is one, which requires careful attention in the design phase, and also the environmental considerations as mentioned above are increasingly driving the selection and operation of process alternatives to reduce the BTEX/VOCs emissions in the atmosphere.
In this paper, we will focus the study on one of the glycol dehydration unit for one of the onshore petroleum fields at Abu Dhabi managed by ADCO. Firstly, we quantify the BTEX/VOCs emission levels vented out to atmosphere, along with a description of the sampling technique used. Secondly, we optimize the process parameters around all major equipments in the glycol unit, i.e. absorber, flash tank, and regenerator. The optimization study will start by building a process simulation model which is based on actual design data given by the glycol unit vendor and verified by operational data.
Replacement of Cold & Cryogenic Insulation on a Live LNG Plant
Authors: Clements G. D. 
Published: December 2007

Abstract
This paper is a review from inception through execution to the status today of an ongoing ADGAS project to replace cold and cryogenic insulation without shutting down, i.e. during operational (live) conditions. It comprises historical background and the technical, operational, safety and environmental, contractual, and commercial aspects of what is thought to be the first large scale application in the Middle East of patented technology for replacing deteriorated cold and cryogenic insulation on live plant. It is a technology that has applications throughout the petrochemical industry wherever the difficult decision of whether to shut down for such repairs has to be made.
Vortex Meter Application for SCADA System Multiphase Flow Measurement
Authors: Hoadley S. F. , Al-Mutalri F. 
Published: December 2007

Abstract
With the introduction of the supervisory control and data acquisition (SCADA) systems, continuous field surveillance and control is made possible. Real time monitoring of producing well parameters i.e. flowing wellhead pressure, wellhead temperature, flowline pressure and flow rates is essential for maintaining production, monitoring well performance and managing field rates. Using remote sensors, the majority of these parameters are easily obtained with the exception of multiphase metering near the wellhead. Often the complexity of the equipment or the accuracy of the flow measurement present challenges for routine monitoring.
This paper outlines a simple process to effectively measure multiphase flow rates using low cost vortex or turbine type meters. Field results of 114 flow measurements before and after liquid/gas separation is presented to illustrate the accuracy level achieved. The results indicate fieldwide application of this technique is viable, in particular, when integrated with a SCADA system.
Monitoring and Controlling the Quality of Well Log Information
Authors: Al-Farisi Omar , Dajani Nasser , Boyd Douglas , Al-Felasi Ali , Al-Khatib Farouk 
Published: December 2007

Abstract
Reservoir management based on inaccurate or wrong information leads to confusion, frustration and poor decisions. Oil company subsurface specialists spend valuable time error checking, filtering and inspecting data extracted from company databases. End-users expect archived data to be correct. Primary objectives of the Petrophysics team in ADMA-OPCO are to deliver log data "fit for purpose"1 and "get it right the first time". To assist in achieving this, a system with measurable progress indicators was set up to plan, monitor, and quality check data and data flow. The foundation of this system is the CDLOGS (Control / Development Logging Sheet). The information provided by this sheet is followed up by OQSID (Operation, Quality, Safety and Interpretation Database), a database of quality indices. Analysis of its statistics highlights problems, corrective actions and allows quality to be continuously improved. These tools are the first steps in our development of a full quality assurance process.
Technology: Catalyst for Coalgas Growth
Authors: Jenkins C. D. 
Published: December 2007

Abstract
Over the past 20 years, coalgas has evolved from a mining nuisance to a robust industry that provides 7% of U.S. gas production. The key to this growth has been the development of new technologies to locate, quantify, and produce coalgas. Over the next 20 years, additional technological advances will be needed to identify new coalgas reservoirs and maximize recoveries from existing ones. Focus areas for these technologies include reservoir characterization, drilling and coring, wireline logging and well testing, completion and stimulation, production and water disposal, and improved recovery methods. This paper identifies some of the key technology needs in each of these areas, reviews recent innovations and showcases emerging technologies.
A Review of the Porter Field Unit Pressure Maintenance Project, Karnes County, Texas
Authors: Randle R.C. , Swaim R.J. 
Published: December 2007

Abstract
The Porter field unit is a 10 well project producing from a Pettus sand reservoir completely enclosed by faulting and sand pinch out. Primary reservoir performance was characterized by rapidly declining reservoir pressure and oil production, and increasing gas-oil ratios. A unit was formed in 1947. The program employed is injection of water down dip and return of produced gas to the gas cap. The project has been highly successful in arresting pressure and production declines and increasing ultimate recovery. Total oil recovery has already exceeded primary estimates by 29 per cent and productive capacity remains high. Movement of the water front has been uniform and water injection continued for four years before water production was obtained in the nearest producer 1,360 ft away.
The success of the project is attributable to the willingness of the operators to conduct a long term project with high water injection pressures, and low injectivity, in order to obtain increased ultimate recovery.

Introduction
The purpose of presenting the history and performance of the Porter field unit is to show how success was achieved in spite of several adverse conditions. The reservoir rock is shaley, containing bentonitic clay. Water available for injection is comparatively fresh. Electric logs and core data show that permeability is variable throughout the field. At the start of water injection, abnormally high pressures were necessary to inject even a limited volume of water. A fair degree of success was obtained, however, and fortunately the second well to be used for this purpose proved to be very much better. Injection of gas has not as yet increased oil production directly. It has served however, to reduce reservoir voidage and hence helped to maintain reservoir pressure.
Use of the Peng-Robinson Equation of State to Predict Hydrocarbon Phase Behavior and Miscibility for Fluid Displacement
Authors: Williams Craig A. , Zana Erdinc N. , Humphrys George E. 
Published: December 2007

Abstract
Recent advances in computer implemented equations of state have made predictions of phase behavior easier and more reliable. They have also led to a different approach in predicting first contact and generated miscibility in hydrocarbon systems. In this study, the Peng-Robinson Equation of State is used to provide equilibrium gas and liquid compositions at reservoir temperature and hypothetical reservoir pressures. In predicting miscibility, a system's two-phase envelope and associated tie lines are displayed as ternary diagrams. From these diagrams, a reservoir engineer can determine the minimum enrichment of intermediates (C2-C6) required for miscibility given reservoir pressure, reservoir fluid composition, and for a fixed reservoir temperature; or the minimum pressure for miscibility, given an injection gas and reservoir fluid composition. Experimental slim tube miscibility study results are compared to the method when available. We have successfully used this procedure to guide our laboratory reservoir evaluation programs, thereby saving experimental time and effort.
Applicability of Steamflooding for Carbonate Reservoirs
Authors: Nolan Jon B. , Ehrlich Robert , Crookston Reid B. 
Published: December 2007

Abstract
Steamflooding can be a technically effective recovery method for carbonate reservoirs within certain parameter ranges. The attractiveness of steamflooding relates to the fact that heat conduction is a powerful mechanism for influencing the oil in the low permeability matrix in a heterogeneous formation, and the characteristically thick pay sections often associated with carbonate reservoirs result in relatively low heat losses to the confining strata.
A numerical simulation model was used to study the effects of varying certain reservoir parameters (thickness, porosity, oil saturation, horizontal permeability, horizontal-to-vertical permeability ratio, well spacing and stratification) on performance parameters (steam-oil ratio, oil recovery and project life). Steam-oil ratios less than 5-1/2 and recoveries greater than 80% in the heated zones were predicted for certain ranges of these parameters that are realistic for some carbonate formations.
Two methods of heat scavenging were investigated using numerical simulation and physical models. The more promising method was simply drawing down the reservoir pressure by continued production after stopping steam injection, thereby generating steam by water flashing in the heated zone. This reduced steam-oil ratio by about 1-1/2 units in our test case, relative to continued steam injection, with only slightly reduced recovery and slightly increased project life.
An Analysis of Predicted Versus Actual Gas Injection Performance of the Williams Reservoir, Coleman County, Texas
Authors: Runyan E.E. 
Published: December 2007

Abstract
In the Williams field reservoir study, the predicted performance agrees very well with the actual performance. The oil recovery was predicted almost exactly, the pressure performance was predicted closely, and the gas-oil ratio performance was approximated. Each of the last two factors was thrown in error since wells were shut in as they went to a high GOR. This practice had not been allowed for in the original reservoir study but became a necessity when it was found impossible to market the excess produced gas.

Introduction
It is the purpose of this paper to apply the accepted reservoir engineering methods of predicting the behavior of closed reservoirs to the Williams field and to compare these predicted results with those actually obtained under gas injection. It is hoped that this comparison, with the original reservoir study based on information available only up to the time of initial gas injection, will indicate the accuracy obtainable in predicting the behavior of this type of reservoir.

Discovery, Development and History
The Williams field was discovered in Nov., 1943 by Hunter and Hunter Oil Co. of Abilene, Tex. in what is now the Williams unit 3. The discovery well was completed in the Gray sand for an initial potential of 8 BOPD with a GOR of 116,000 cu ft of gas/bbl. Development proceeded at a moderate rate with 14 wells drilled in 1944 and 13 in 1945. Five wells were dry and two were completed in a small separate reservoir to the west of the main reservoir. All wells were drilled with rotary tools and spacing followed a nearly regular 40-acre pattern.
Completion practices included setting 100 ft of 10 3/4 in. surface pipe, drilling to the top of the Gray sand, coring the entire pay interval, logging, and setting a 5 1/2 in. production string through the gas cap. Therefore, all wells are producing from the open hole.