bluuebunny/crossref_metadata_2025_split huggingface dataset:
Viscosifying Surfactant Technology for Chemical EOR: A Reservoir Case
Authors: Degré G. , Morvan M. , Beaumont J. , Colin A. , Dupuis G. , Zaitoun A. , Al-Maamari R. S. , Al-Hashmi A. R. , Al-Sharji H. H. 
Published: April 2012

Abstract
Recent publications indicate that the injection of polymer solutions at concentrations larger than those conventionally used in polymer flooding can result in higher recovery at field scale. Typically, oil recovery more than 20% OOIP compared to waterflooding using these polymer solutions has been reported (Wang et al; 2011). However, injectivity issues have to be considered when injecting such concentrated polymer solutions. This study describes an alternative approach based on surfactant-based solutions. The technology has been developed to match the rheological properties of polymer solutions in a broad range of reservoir conditions (temperature & salinity) without any injectivity limitations even when considering very viscous surfactant solutions (i.e. up to 1000 cps) and low permeability cores.
Average first normal stress difference measurements have been used to compare the elastic properties of surfactant and high-molecular-weight polymer solutions. The degree of non-linearity in the mechanical properties for both solutions has been expressed by Weissenberg number. The surfactant solution has much higher Weissenberg number than the polymer solution at a shear rate corresponding to the fluid propagation in the reservoir, which indicates higher elasiticily of these surfactant solutions.
The potential of this surfactant-based technology is illustrated through a specific reservoir case involving heavy oil. A series of coreflood experiments has been performed in reservoir cores at reservoir conditions. The surfactant slug can be combined with a conventional low-concentration polymer flooding to further improve the process. Reduction in residual oil saturation in the range of 10 to 15% has been obtained. Complementary simulation study giving rise to economic analysis have been performed.
The Integration of Miscible Gas Injection in Oil Reservoirs with the Development of a Sour Gas Condensate Field
Authors: Vissers J. M. , Alkindi Abdullah , Hassan A 
Published: April 2012

Abstract
This paper describes the integration of the development of a number of oil reservoirs by means of miscible gas injection with the development of a gas condensate field.
Around the year 2000 a number of oil reservoirs were discovered in south Oman. Material Balance calculations and early performance data confirmed the geological predictions that little or no aquifer support was to be expected from those reservoirs. Recovery factors based on primary depletion are limited to about 10%, and to boost recovery miscible gas injection (MGI) was identified as the most promising technique.
The gas needed for such miscible gas flood was found in the presence of a gas condensate field located nearby. The gas contains about 15% CO2 and 3% H2S and is considered a sour gas development. Originally the gas-condensate field was scheduled for stand-alone development, with gas sweetening and re-injection of the waste stream, containing about 70% CO2 and 30% H2S, to maximize condensate recovery. The integration of the gas and oil development offered an additional sink for the waste gas, as this could now be used for MGI.
To optimize the development, in terms of maximizing the Ultimate Recovery, a fully compositional model, integrating the 3D subsurface modeling and surface network, was constructed. The model was used to determine the best strategy for the MGI development of the portfolio of oil reservoirs, assess the impact of sour gas injection in those oil fields on existing production facilities, and select the optimum gas offtake from the gas field.
The integrated modeling enabled the selection of a development concept that maximizes the UR of the Oil and Gas fields, ensures the Gas sales commitments, while making maximum use of the existing facilities, thereby maximizing the monetary value of the project.
1D Asphaltene Deposition Simulator for Reservoir Fluids Undergoing Gas Injection
Authors: Pedersen Karen Schou , Shaikh Jawad Azeem , Rasmussen Claus P. 
Published: April 2012

Abstract
CO2 and hydrocarbon gas injection are interesting Enhanced Oil Recovery (EOR) techniques for oil reservoirs. Gas injection may initiate asphaltene precipitation in a reservoir. 1D compositional CO2 gas injection simulations have been conducted to find out where asphaltenes will precipitate and deposit. It was found that asphaltenes will precipitate in the transition zone between injection gas and oil. This transition zone will move forward continuously and no accumulation of asphaltene deposit will take place. Though deposited asphaltenes locally will plug reservoir pores and decrease permeability, this is unlikely to affect the oil recovery. The mobility of the gas and oil phases is high in the gas-oil transition zone where asphaltenes precipitate, and those high mobile phases will manage to bypass a small volume fraction of deposited asphaltenes. With an asphaltene phase present in addition to gas and oil the classical definition of a miscible gas drive cannot be fulfilled. Miscibility can however develop between an injection gas and an oil phase, which through contact with gas has been stripped for asphaltene components.
Single Well Chemical Tracer Tests - Fast and Accurate Simulations
Authors: Huseby Olaf , Sagen Jan , Dugstad Øyvind 
Published: April 2012

Abstract
In EOR-operations, the single-well chemical tracer test (SWCTT) has been proven as a secure and stable methodology for measuring oil saturation prior to and after application of EOR-measures. SWCTTs can be used to measure residual oil saturation in a near-well region up to about 10 m from the wellbore, and has been used in several hundred studies, in particular in the US. Current simulation of SWCTT requires a reactive transport modelling tool that allows for a hydrolysis reaction involving four chemical compounds, in addition to other chemical tracers used in specific tests. Today compositional reservoir simulators are usually applied to simulate SWCTTs.
In this paper we show that the SWCTT modelling can be made much simpler, without compromising a correct description of the reactive transport process. The formulation of the solution exploits the fundamental assumption that tracers do not affect the phase transport. A fast post-processing tracer simulation technique is introduced to solve single well tracer transport in real-life reservoir cases. The partitioning and reactions of the tracer components is solved fully coupled with the tracer transport, and partitioning between phases is described by a convenient formulation and the ester hydrolysis reaction is modelled in an efficient manner. The post-processing is based on previously solved reservoir simulation runs and gives significant savings in CPU-time.
Using an experimental case and one field case, we demonstrate the practical improvement achieved by the new method, and investigate effects of numerical smearing. Our main conclusion is that the formulation is important to enhance correct evaluation of SWCTT results.
Wettability and Oil Recovery by Low Salinity Injection
Authors: Shiran Behruz Shaker , Skauge Arne 
Published: April 2012

Abstract
Low salinity has been studied extensively, but still the mechanisms for improved oil recovery by lowering brine salinity are unsolved. The target of this paper was to address this problem and make systematic studies that can give insight to the key mechanisms. Given the variety of conditions under which increased recovery by low salinity brine injection may or may not be observed, it is likely that more than one mechanism is contributing to the observed oil recovery. The mechanisms most claimed to be the reason for improved oil recovery are shift in wettability, multi-component ion exchange, and dissolution/fines migration.
In this paper, we have studied low salinity waterflood by systematic changing the rock wettability. The wettability is changed by varying aging with crude oil at elevated temperature. We are investigating how aging time effect affects core analysis properties like; spontaneous imbibition, Amott-Harvey and USBM wettability oil and water indices. The wetting properties were also cross-checked by NMR.
The detailed core analysis is the background for study of oil recovery by seawater injection and subsequent lowering of salinity. In addition to detecting trends of initial wetting and the potential for low salinity, all mechanisms for low salinity recovery are discussed. It is expected from the literature that the clay content in Berea cores favors oil recovery by low salinity waterflooding, however the more oil wet character of the Bentheimer cores in this study, seems more important for improved oil recovery by low salinity waterflood.
Challenges in Implementing an EOR Project in the Pre-Salt Province in Deep Offshore Brasil
Authors: de Sant´Anna Pizarro Jorge Oscar , Branco Celso Cesar 
Published: April 2012

Abstract
Carbonate reservoirs contain expressive part of the world oil reserves. The exploitation of these resources, however, presents several challenges mainly associated with their complex pore geometry, large scale variation in permeability and sometimes unfavorable wettability. These challenges can become more significant when we move to a deep offshore environment. As off-shore projects need to be planned well in advance, due to the lack of room in the platforms for future expansion, the pioneer application of EOR methods needs to be considered from the conceptual stage of the development.
This paper addresses the approach used to design the development basis for Lula field, formerly known as Tupi area, in the Pre-Salt Cluster (SBPSC) in Santos Basin, offshore Brazil. It focuses on the strategy of phased development, dynamic data acquisition and actions to add flexibility to the production system and how to manage uncertainties. A comprehensive analysis of the existing uncertainties, such as the reservoir characterization, early water and gas breakthrough, bypassed oil saturation, flow assurance in deep water flowlines and CaCO3 scale possibility in production wells, favored a phased development concept aiming to mitigate risks. The approach used to cope with these uncertainties in a Pilot Project as well as in the future development scenarios is presented. Most of the discussion is focused on how to consider feasible Enhanced Oil Recovery techniques through Pilot testing and future implementation in large scale in the field. It comprises the investigation of different recovery processes and first field results, including miscible processes using hydrocarbon gas and CO2. To optimize the oil displacement, a water alternating gas (WAG) injection process is also being designed.
After one and a half year of extended well test production and the implementation of the first Pilot project in January, 2011, results confirm the decision of providing additional flexibility to the project. Dynamic appraisal proved essential to assess reservoir connectivity, evaluate stimulation methods, support reservoir characterization studies and define aspects related to flow in subsea lines. The first results of the injection of the CO2 stream, separated from the associated gas in the Pilot project, indicate that the chosen strategy has potential to be a successful one. The continuing production and pressure data monitoring of the WAG implementation in the Pilot, from 2012 on, will provide a more definitive conclusion about the feasibility. Good responses will translate in the EOR expansion to field scale.
Drilling Automation: Presenting a Framework for Automated Operations
Authors: Breyholtz Øyvind , Nikolaou Michael 
Published: April 2012

Summary
This paper will present and discuss drilling automation on the basis of a "mode of automation" approach. Different modes of automation will be presented and explained. In particular, the paper will focus on how closed-loop control can enable higher modes of automation, which is essential to improve the operational and economic performance of drilling operations. Introducing a higher mode of automation may lead to optimal performance, but it also introduces new safety issues that need to be addressed in order to ensure safe conditions in the well. For each increased mode of automation, the work distribution between the automation system and the driller changes and a clear understanding of the human/ machine interaction at each mode of automation is needed.
The Skin Effect and Its Influence on the Productive Capacity of a Well
Authors: Van Everdingen A.F. 
Published: April 2012

Abstract
The pressure drop in a well per unit rate of flow is controlled by the resistance of the formation, the viscosity of the fluid, and the additional resistance concentrated around the well bore resulting from the drilling and completion technique employed and, perhaps, from the production practices used. The pressure drop caused by this additional resistance is defined in this paper as the skin effect, denoted by the symbol S. This skin effect considerably detracts from a well's capacity to produce. Methods are given to determine quantitativelythe value of S,the final build-up pressure, andthe product of average permeability times the thickness of the producing formation.

Introduction
Equations which relate the pressure in a well producing from a homogeneous formation with pressures existing at various distances around the well are generally used within the industry. The relation is quite simple when the fluid flowing is assumed to be incompressible. It becomes somewhat more complicated when the flowing fluid is considered compressible so that the duration of the flow can be considered. In each case the major portion of the pressure drop occurs close to the well bore. However analyses of pressure build-up curves indicate that the pressure drop in the vicinity of the well bore is greater than that computed from these equations using the known, physical characteristics of the formation and the fluids. In order to explain these excessive drops it is necessary to assume that permeability of the formation at and near the well bore is substantially reduced as a result of drilling, completion and, perhaps, production practice. This possibility has been recognized in the literature.
A method to compute the pressure drop due to a reduction of the permeability of the formation near the well bore, which is designated as the skin effect, S, is given in the following paragraphs. To start, equations normally used to describe flow in the vicinity of a well are given without considering this effect. These equations then are modified to include the effect of a skin on the pressure behavior. Finally a method is given to estimate the effect of the skin on the pressure and production behavior of a well.
Spraberry Permeability From Build-Up Curve Analyses
Authors: Dyes A.B. , Johnston O.C. 
Published: April 2012

Abstract
The application of a method for analyzing pressure build-up curves to determine the effective permeability in the Spraberry is presented. Sixteen Upper Spraberry wells of the Driver area are analyzed and show variations in the in-place effective permeability of 2 to 183 md. Since these values are much larger than the.5 md, or less, reported for the matrix rock, a large part of the vertical fractures noted in Spraberry cores must be considered native to the formation.
The effectiveness of the well fracture treatment in connecting the well bore to the native fracture system is analyzed by comparison of the effective permeability as determined from the PI test to that obtained from a pressure build-up curve. These results show that the fracture treatment is sufficiently effective in connecting the well bore to the native fracture system to yield a flow capacity within about ?50 per cent of that dictated by the native fracture system. About two-thirds of the wells show some degree of local blockage.

Introduction
Fractured reservoirs have been known in the past: However, during the past two years the Spraberry formation has directed the attention of the petroleum industry to a study of the performance of a fractured reservoir. The large variation in the number of fractures noted in Spraberry cores, the large variation in the producing ability of offset wells, the dramatic effect of well treatment on well productivity, the unknown quantity of oil stored in the fractures and matrix rock, and the unknown oil to be recovered were part of the initial Spraberry puzzle.
In this type reservoir where the well treatment is an important factor in determining the productivity, it is particularly desirable to determine the in-place flow capacity of the drainage area at distances far removed from the well bore. This value, when compared to the flow capacity obtained from a PI measurement, will show the effectiveness of the well treatment (completion, fracture treatment, acidization, etc.) in establishing a flow capacity in the vicinity of the well bore equal to that in the more remote region. The object of this paper is to show the application of a method of pressure build-up analysis for this purpose in studying the Upper Spraberry formation in the Driver area.
The Core Recorder
Authors: Millison Clark 
Published: April 2012

Abstract
The core recorder, a mechanical instrument for determining the exact depthat which core is recovered, drilled up or lost, is described. Examples ofcharts from the recorder are explained and interpreted. The uses of the corerecorder are discussed.

Introduction
In the experience of geologists and engineers during coring operations ondrilling wells, many will recall the times when a full core was not recoveredand particularly when the requirement was urgent that they know exactly whatpart of the core was lost. To make this determination, the core recorder wasdesigned. Its uses are many, and only the most obvious will be presented here.Although this discussion will be limited to drilling wells for petroleum, thecore recorder can be used in any type of coring operation.
The principle of the core recorder is the proportional reduction of themotion of core entering or dropping out of the core barrel to a stylus movingin such a manner as to record the reduced motion on a chart. The time elementis registered on the same chart by the revolution of a clock which turns thechart drum. Thus the exact amount of core entering or dropping out of the corebarrel is charted and the time of such entry or exit from the core barrel isprecisely correlated to the depth at which the core is recovered or lost. Lackof movement of the stylus which is revealed by the continued revolution of thechart drum indicates that no core is entering the barrel.
The principles are accomplished by an instrument placed inside of the corebarrel. A cylinder which contains the clock and mechanical apparatus has adiameter smaller than that of the core barrel. Near the top of the cylinder isan eighteen hour clock which turns the drum that contains the chart. Near thebottom of the instrument is a serrated wheel which by friction against theinside of the core barrel is turned as core enters or drops out of thebarrel.
T.P. 2542
A Study of Oil and Gas Conservation in the Pickton Field
Authors: Welsh J.R. , Simpson R.E. , Smith J.W. , Yust C.S. 
Published: April 2012

Abstract
This paper presents the results of a complete reservoir study designed todetermine a sound economic program for the conservation of oil and gas in thePickton field, Hopkins County, Texas. The Pickton field produces from the BaconLime with all indications of the study being that production is predominatelyby dissolved-gas drive. Calculations of the total ultimate recovery to beexpected under primary operations indicated only 16.7 per cent of the oiloriginally in place would be recovered. This unusually low recovery is due tothe type of drive operating and the extremely high dissolved gas-oil ratio andshrinkage.
Results are presented for six plans of returning gas to the reservoir, evaluated to determinecomparative recoveries and economics ofreturning gas at a constant rate by supplementing Pickton gas with extraneousgas during the early portion of the operation, andconventional gas-returnoperations without using extraneous gas, andthe optimum size of compressorplant for each type of pressure maintenance.
The over-all economic program considers, for either type pressuremaintenance operation, a gasoline plant to process the unusually richcasinghead gas. Since pressure maintenance will disturb equities, pooling ofroyalties is in the case of Pickton a prerequisite to conservation of oil bythis type of operation, both from an economic and legal standpoint. In theevent pooling of royalties cannot be achieved, the study considers a gasolineplant to operate under a modified primary production operation which will makethe conservation of gas possible.

Introduction
The Pickton field, located in Hopkins County, Texas, was discovered inNovember, 1944, by the completion of Humble's C. D. Nichols 1, in the Baconlime of the Lower Glen Rose formation, through perforations from 7,888 to 7,896feet. The well initially produced 50.2 API gravity oil with a gasoil ratio of1,350 cubic feet per barrel. Subsurface samples of the reservoir fluid obtainedsoon after completion of the discovery well showed that the Pickton crude isunique in that it has an extremely high dissolved gas-oil ratio and is subjectto very severe shrinkage.
T.P. 2564