bluuebunny/crossref_metadata_2025_split huggingface dataset:
Field Application of a Novel Emulsified Scale Inhibitor System to Mitigate Calcium Carbonate Scale in a Low Temperature, Low Pressure Sandstone Reservoir in Saudi Arabia
Authors: Nasr-El-Din H. A. , Lynn J. D. , Hashem M. K. , Bitar G. 
Published: December 2007

Abstract
This paper describes field application of a novel scale inhibitor squeeze treatment to mitigate downhole scale (calcium carbonate) present in several oil producing wells in a sandstone reservoir in central Saudi Arabia. The sandstone reservoir is weakly consolidated, water sensitive, and sanding problems were noted in several wells. The water cut in the scaled wells ranges from 3 to 80 vol%. To avoid sanding problems, most of these wells were gravel packed. In addition, the reservoir pressure and gas oil ratio are low and, as a result, electrical submersible pumps (ESPs) are used to produce these wells. The sandstone reservoir is heterogeneous and contains up to 14 wt% clay minerals in some zones. The bottom hole temperature is nearly 160°F. A thorough investigation was undertaken to develop a suitable scale squeeze treatment to mitigate the scale, and to assess the effectiveness of the treatment in the field.
Based on extensive lab studies, a new emulsified scale inhibitor treatment was designed and applied in more than fifteen wells. These wells were descaled prior to the squeeze treatment as was detailed by Nasr-El-Din et al.1 All scale squeeze treatments were conducted using 1.75 or 2 in coiled tubing. Because the formation is water-sensitive, the main treatment, the pre and post flushes were designed to minimize formation damage due to fines migration and clay swelling. Following the treatment, the well was shut-in for two days to give ample time for various reactions to occur. Chemical analysis of well flow back samples was used to estimate the lifetime of the squeeze treatment. In addition, a downhole video camera was used to follow scale formation following the treatment.
The scale squeeze treatment was conducted in more than fifteen wells. The emulsified inhibitor was mixed in the field and was injected into the target zones without encountering any operational problems. Analysis of flowback samples indicated that the treatment did not affect well productivity or water cut in any of the treated wells. Based on field data, it is known that the treatment lifetime is greater than two years. The minimum scale inhibitor concentration, presented as phosphorus, is nearly 1 mg/L.
Getting the Best From Formation Tester Sampling
Authors: Hy-Billiot J. , Bickert J. , Montel F. , Segalini G. 
Published: December 2007

Abstract
Formation Testers provide valuable information on compositional gradient within a reservoir fluid column. But it has been established that fluid samples obtained with oil-based muds (OBM) are contaminated by the filtrate to an extent dependent on the "pump out" time and the original fluid properties. Except in some very specific cases, the contamination reaches a residual asymptotic level with the pump-out duration. When fluid viscosity is high, the residual contamination is high too and its impact on the physical properties can be huge.
New techniques have been developped to deal with contaminated samples. This paper describes different ways to get rid of contamination and assess the reservoir fluid composition and associated PVT properties. It then offers some recommendations for sampling procedures. A distinction is made between simple miscible cases and complex two-phase cases where the mass exchange between reservoir fluid and filtrate is no longer negligible. Three decontamination methods are presented, and the reliability of the calculated properties of the de-contaminated fluid is discussed.
Through field examples, the paper provides a methodology for dealing with contaminated samples and tips for getting the best from Formation Tester samples.
The main contributions are the methodology for decontamination of Formation Tester samples in the case of OBM drilling, and the integration of the information from this sampling tool into the reservoir fluid evaluation procedure
Prediction of Capillary Fluid Interfaces During Gas or Water Coning in Vertical Wells
Authors: Johns Russell T. , Lake Larry W. , Delliste Arnaud M. 
Published: December 2007

Abstract
Gas and water coning cause oil production to be significantly reduced and costs associated with the production to be significantly increased. Simulation and experimental methods, coupled with simple analytical solutions or correlations, are typically used to identify the oil rate that minimizes coning and maximizes recovery. Current analytical solutions, however, assume negligible capillary pressure, which leads to segregated flow. This paper presents new analytical solutions that relax this assumption.
The new coning solutions apply to vertical wells where in situ fluids are in vertical equilibrium. The development identifies the important dimensionless groups that control the effect of coning on oil recovery and illustrates how simultaneous two-phase flow affects capillary fluid levels in the formation. Dimensionless two-phase production windows are constructed to identify critical rates, the largest oil rate at which water (or gas) will not be produced.
A Method for Developing Rock Mechanical Property Logs using Electrofacies and Core Data
Authors: Miskimins Jennifer , Hurley Neil , Graves Ramona 
Published: December 2007

Abstract
A methodology for developing an extremely detailed, synthetic rock-mechanical properties log is presented. The technique uses electrofacies developed from FMI images in conjunction with rock properties measured directly from core. The analysis is performed using data from the North LaBarge Shallow Unit (NLBSU) located in the Green River basin in southwest Wyoming. The NLBSU produces from Cretaceous Mesaverde sandstone that consists of thinly bedded sand and shale layers. These laminated layers are generally less than 1.5 inches (4 cm) thick.
Hydraulic fracturing is necessary for economical production from the NLBSU wells. The thin-bedded nature, as well as the low permeability associated with the reservoir, requires this completion technique. As such, an understanding of how hydraulic fractures grow in this thin-bedded environment is essential.
Acoustic measurements taken approximately every 0.5 inches (1.3 cm) on 90 ft (27.4 m) of core provide a detailed mechanical properties log for that particular section of the well. A relationship between these properties and the conductivity readings from the FMI log is developed which allows extrapolation of the rock-mechanical properties to the uncored sections of the subject well. Extrapolation of the rock-mechanical properties to other wells in the field is also possible.1 The resolution provided by the FMI log permits a detailed rock-mechanical log to be developed for the entire well. This rock-mechanical properties log exhibits significantly more detail than similar logs developed using dipole sonic logs.
The described methodology is being used to improve hydraulic fracturing techniques in the subject field. The technique presented can be used in other fields, thus providing an aid to improving hydraulic fracturing models. Other simulation techniques that require mechanical properties, such as reservoir modeling or wellbore stability models, could also benefit from improved input data provided by this technique.
Terang/Sirasun Field Development: Geohazards Engineering
Authors: Smith N. T. G. , Jayson D. M. , Fenton C. H. , Gillies M. 
Published: December 2007

Abstract
The Terang, Batur, East and West Sirasun gas reservoirs are located 120 km north of Bali on the Kangean shelf of the North Bali Basin, in water depths ranging from 100 to 300 metres. The reservoirs collectively contain around 1 TCF of recoverable gas. It is proposed to jointly develop the reservoirs by means of a subsea development and associated floating production unit (FPU), with gas being exported to the nearby East Java Gas Pipeline for onward transmission to Java.
The North Bali basin lies above a major subduction zone, and is consequently an area of extensive seismic and volcanic activity. The proposed Terang/Sirasun development location is subject to numerous geohazards, including fault rupture, shallow gas, slope instability, liquefaction, and strong earthquake shaking. These geohazards pose risks to safety, the environment and the field facilities, both during construction and during production operations. Consequently, a key element of the early engineering definition phase of the project, prior to undertaking FEED, has been the analysis and quantification of the geohazard risks.
A geohazards engineering programme was undertaken during 2000 – 2001. An integrated multidisciplinary team was assembled, covering the geophysics, geology, drilling, completions, subsea and facilities disciplines. An extensive data acquisition programme was undertaken, comprising some 5,600km of 2D seismic lines, swathe bathymetry, sidescan sonar, sub-bottom profiling and geotechnical sampling. The team used state-of-the-art visualisation technology to map the hazards and plan wellbore trajectories and facility locations to minimise risk. Limit state analyses of the wells and seabed facilities were performed to determine capacity to respond to seismically triggered events. Finally, extensive probabilisitc analysis utilising decision (or logic) trees was undertaken to quantify the safety and economic consequences of geohazard events in terms of environmental impact, asset damage and production interruption.
This paper describes the geohazards engineering programme and presents lessons learned. The programme received a commendation in BP's internal Helios Awards scheme during 2001.
Oil Well Performance In The Presence Of A Gas Phase
Authors: Hassan M. 
Published: December 2007

Abstract
Production and pressure build-up tests conducted on several wells at different stages of reservoir depletion are examined. The objectives are two-fold; to evaluate the deterioration of well productivity during two-phase flow and, to find a procedure to estimate the single phase transmissibility from pressure build-up tests carried out in the presence of free gas saturation.
Satisfactory results are obtained when the relative permeability effect is accounted for in the following manner; the flowing period is described as a drainage process whereas the closed-in period is assumed to resemble an imbibition behaviour. In addition, the portion of the well drainage area in which gas saturation is below the critical value is assumed to have a constant effective permeability to oil. The last assumption is supported by actual well performance.

Introduction
The flowing and shut-in performance of oil wells producing from a multiphase, oil-gas, system has been investigated. This work has been based on data acquired from production and pressure build-up tests performed on wells producing from the Bu Hasa Shuaiba reservoir situated on-shore in Abu Dhabi in the United Arab Emirates. The field is presently operated by Abu Dhabi Company for Onshore Oil Operations.
The reservoir was brought on stream in 1965 and produced by fluid expansion for about seven years before a peripheral water flood was initiated to arrest the rapid decline in reservoir pressure. At the reservoir crest the pressure fill to a level of about 100 psi above the local saturation pressure and some of the crestal wells were flowing at a bottom hole pressure 700 psi below the bubble pressure 700 psi below the bubble point. Under such conditions severe point. Under such conditions severe deterioration in the productivity index was observed but well productivity was recovered after several productivity was recovered after several months of either shutting-in the well or beaning back the production so that the bottom hole flowing pressure remained above the saturation pressure.
The objective of this study was to identify a procedure to predict the inflow performance below the bubble point and to evaluate the point and to evaluate the permeability to oil as a single phase from permeability to oil as a single phase from pressure build-up tests performed in pressure build-up tests performed in the presence of free gas saturation.
Horizontal radial flow and homogeneous reservoir rock characteristics have been considered. The porosity, permeability and irreducible water permeability and irreducible water saturation were assumed to remain constant with depletion.

FIELD RESULTS

Flowing Well Performance
Producing rates and bottom hole pressure measurements have been pressure measurements have been closely monitored throughout the history of the wells considered here.
Geopressure Detection Using Reflection Seismic Data and Rock Physics Principles: Methodology and Case Histories From Deepwater Tertiary Clastics Basins
Authors: Dutta Nader C. 
Published: December 2007

Abstract
Subsurface formations with pore fluid pressure in excess of the hydrostatic pressure (geopressure) are encountered worldwide. Although there are a multitude of causes that can result in geopressure, under compaction due to rapid burial of sediments is the predominant cause of geopressure. Typically, if the loading process is rapid, fluid expulsion through compaction is severely retarded, especially in fine-grained sediments with low permeability such as silts or clays. This results in stress redistribution within the column -a greater proportion of the overlying weight of the sediments is borne by the fluids than when the sediments compact normally, causing a decrease in the stress acting on the rock framework. Dehydrating bound water from clays within shales further complicates this phenomenon as compaction proceeds with the depth of burial with increase in temperature.
Geopressured formations pose significant threats to drilling safety, and the cost of mitigation, especially, in deepwater settings, is high…to the tune of $1.08 billion per year world-wide. Proper planning before drilling is key to lowering costs and increasing safety. In this regard, the role of seismic is of paramount importance. Seismic wave attributes (amplitude, velocity, coherency, etc.) are affected when stresses acting on the sedimentary column (effective or differential stress) are low. These attributes can be analyzed to obtain signatures, or lack of fluid transport over the geologic time- both qualitatively and quantitatively. Using the seismic, zones of trapped fluids and pressured compartments can also be mapped prior to drilling. With either an analogue or a reliable low-frequency velocity model, it is also possible to map fluid transport effects in the reservoir scale using seismic inversion techniques.
In this paper, we illustrate how this process works using seismic data at various scales, from the low frequency reflection seismic at exploration frequency scales to those employed at well-logging scales. A rock-model-based approach especially suited for deepwater pore pressure imaging is introduced. It includes the effect of shale burial diagenesis, and uses the velocities derived from inversion of prestack seismic data. The procedure yields details of pre-drill pore pressure images with significant clarity as well as pressure versus depth profiles appropriate for drilling applications. In particular, prestack full waveform inversion yields Poisson's ratios that are useful not only for pressure and fracture gradient estimations but also for lithology and fluid identification. This technique is also applicable to identification of shallow water flow formations that pose drilling hazards in deep water. The procedure is illustrated with examples from several deepwater basins.
Application of Multilateral Technology in Drilling an Offshore Well, Indonesia
Authors: Tanjung Erwindo , Saridjo R. , Provance Stan M. , Brown Pat , O'Rourke Tim 
Published: December 2007

Abstract
This paper presents the case study of the implementation of multilateral technology for Repsol-YPF Maxus in East Rama field, Southeast Sumatra concession, Indonesia. Repsol-YPF wanted to introduce multilateral technology in an attempt to reduce overall cost related to drilling, production and facilities; as well as increase slot availability on its offshore platforms. Drilling two successful pilot wells with the BIMA Multi Purpose Service Vessel (MPSV) in August of 2001 initiated the project. One pilot well, East Rama AC-6P, was drilled vertically and the other pilot, East Rama AC-7P, drilled directionally by sidetracking from the East Rama AC-6P surface casing. These pilot wells successfully discovered two hydrocarbon bearing pay sands in the Talang Akar formation. Based on this success the East Rama field had a need to drill additional producing wells. With the slot limitation on the platform (i.e. one available slot coupled with the desire to achieve optimal reservoir recovery), multilateral technology was selected. The use of this technology was not just to prove its' viability for well construction resulting in future savings of field development projects, but also to calculate and compare two single well costs to one multilateral. This paper categorizes the reasons for choosing multilateral well as the development option, planning and preparation of the well, and all results of the operations. Issues covered include strategic well design, economic analysis, and the problems encountered during drilling operation. The lessons learned are documented and presented as a reference for future developments, specifically for multilateral technology and generally for drilling improvement.
Application of Neural Network to the Determination of Well-Test Interpretation Model for Horizontal Wells
Authors: Sultan Mir Asif , Al-Kaabi Abdulaziz U. 
Published: December 2007

Abstract
Well-test model identification and, subsequently, model parameters determination are more complex in horizontal wells than in vertical wells. This is due to the increase in number of flow regimes occurring during a flow period and the fact that strong correlation exists between model parameters.
This study presents a new approach for automatic model identification and computer-aided well-test interpretation in horizontal wells. The new approach is based on using neural network to (1) identify the well-test interpretation model; (2) identify flow regimes; and (3) mark the position of identified flow regions on the derivative plot of well test data.
This work consists of first generating common model signatures using Ozkan and Ragavan analytical solutions for horizontal wells in various reservoir and inner boundary conditions assuming laterally boundless reservoirs. Next, these signatures are used to train neural networks for three identification stages; model identification, flow regime identification, and position of flow regime identification. Separate networks were trained, then tested and validated using synthetic as well as field data. Once the three identification stages are completed, specialized plots for data points falling into each flow regime are used to determine initial model parameters. Final model parameters are determined using nonlinear regression.
A comparative study was carried out using different network architectures. Modular approach with direct data utilization is found to be most suitable for implementation of our approach.
Effect Of Well Locations On The Performance Of A Multilayered Reservoir
Authors: Abed A.F. , Hadidi A.M. 
Published: December 2007

Abstract
Well location is only one variable of several variables that affect the performance of a multilayered reservoir. performance of a multilayered reservoir. In order to optimize development as well as production plans pertinent to any reservoir it is a good oil field practice to study all these dependent variables of the recovery factor function. In this paper the study of well location variable paper the study of well location variable will be only presented.
A series of reservoir model studies using detailed grid configurations was performed to study the effect of well performed to study the effect of well locations on the performance of different layers in a reservoir of large gas cap and relatively thick oil column and producing under pressure maintenance.
The results showed that, keeping all other dependent variables relatively constant, the well locations have a considerable effect on the performance of different layers. Vertical sweep efficiencies in one case were seen to vary from 25% to 32% of the initial oil-in-place at the end of the same prediction period. The studies also showed that the sweep efficiency increases with increasing distance between the producers and injectors.

Introduction
Recovery of hydrocarbon reserves is a function of several variables which are connected by one or more relations. The reservoir engineering variables of the recovery function are areal sweep, vertical sweep and microscopic displacement efficiencies. Each one efficiency is a function of several variables. It is very difficult, if not impossible, to optimize analytically the recovery function because of the implicitness of the relations connecting different variables. However, the recovery function can be optimized numerically using reservoir simulation models.
For a function of several variables it is very important to define the variables and their interrelation. For example all rock and fluid properties are functions of pressure and temperature levels. Well pressure and temperature levels. Well location is only one variable of several variables that influence the performance of a reservoir by affecting the areal and vertical sweep efficiencies.
This paper describes the effect of well locations on the performance of a multilayered reservoir.
Strategic Decision Making in the Upstream Oil and Gas Industry: Exploring Intuition and Analysis
Authors: Dinnie N. C , Fletcher A. J. P , Finch J. H 
Published: December 2007

Abstract
This paper reports on research examining established decisionmaking in the Upstream Oil and Gas Industry. Two important aspects of the strategic decision making process are high-lighted. The main emphasis is on exploring the often neglected intuitive (or non-analytical aspects) of the process although the analytical aspects will also be highlighted and both aspects will be considered in combination. As a means of comparison across companies, companies will then be grouped into different typologies based on the different emphases they place on the intuitive/ analytical aspects. Finally, a model of strategic decision making will be presented which integrates various aspects of the decision making processa. This research is based on analysing the information derived from fifty three face-to-face interviews with individuals working in the UKCS and in Australia who had knowledge of the strategic decision-making process. Eleven operators and one contractor were involved in the study. Initially, open-ended interviews were conducted and this was later followed by semi-structured in-depth interviews. A grounded theory approach was used to analyse the results. Ultimately, it is hoped that the research will be of interest to companies who wish to increase the transparency and their understanding of the strategic decision making process. It will also help companies both to recognise and accrue the valuable contribution of both intuition and analysis in strategic decision making. It is also suggested that although the intuitive aspects may be less visible and widely acknowledged due to their tacitness, difficulty in being codified and communicated, under certain ‘unique’ circumstances as evidenced by ‘intuitive decisions’ they may become more visible, codified and more easily articulated and shared.