bluuebunny/crossref_metadata_2025_split huggingface dataset:
Monitoring Chemical EOR Processes
Authors: Mitchell Jonathan , Staniland John , Wilson Alex , Howe Andrew , Clarke Andrew , Fordham Edmund J. , Edwards John , Faber Rien , Bouwmeester Ron 
Published: June 2014

Abstract
A laboratory study on core plugs from a carbonate field confirmed the efficacy of an alkaline surfactant (AS) formulation at reservoir conditions. Continuous monitoring of remaining oil saturation (ROS) in short core plugs using spatially resolved nuclear magnetic resonance (NMR) can provide insights into the processes by which surfactants release post-water-flood remaining oil. In single short plugs, volumetric averages do not correctly quantify remaining oil due to capillary end effects (high remaining oil saturation post water flood observed at the outlet face of the plug), oil banks, and other flow heterogeneities. These effects are all quantifiable by NMR, allowing accurate monitoring of ROS. Here, consistent ROS values are obtained in the laboratory, in single-well pilots, and in single-well chemical-tracer (SWCT) tests. Laboratory core floods with nuclear magnetic resonance (NMR) monitoring at low magnetic fields therefore provide a valuable calibration of the NMR logs, in addition to the direct assessment of ROS. Corroboration across multiple length scales, spatial resolution, and correspondence with preferred logging measurements, all contribute to the value of NMR-monitored core-floods as a complement to field pilot studies.
West Salym ASP Pilot: Project Front-End Engineering
Authors: Karpan V. M. , Volokitin Y. I , Shuster M. Y. , Tigchelaar W. , Chmuzh I. V. , Koltsov I. N. , Tkachev I. V. , van Batenburg D. W. , Faber M. J. , Skripkin A. 
Published: June 2014

Abstract
Salym Petroleum Development N.V. (SPD) is a joint venture company of Shell and Gazprom Neft. SPD operates a group of oil fields located in Western Siberia (Russia) of which West Salym is the largest. The field is a mature waterflood with increasing water cuts and declining oil production. To counter the decline a tertiary oil recovery technique called Alkaline-Surfactant-Polymer (ASP) flooding was selected. According to our earlier studies the potential incremental oil recovery factor due to ASP injection may reach 15-20% of the ASP-targeted field STOIIP. Having identified significant target for the ASP flooding, SPD carried out laboratory program to establish a working ASP formulation. The formulation was tested under subsurface conditions in a single-well chemical tracer field trial. The trial has demonstrated significant reduction of oil saturation in the flooded zone due to the ASP injection. An investment decision for the next development stage of the West Salym ASP project, a multi-well injection - production pilot, was taken in Q4 2012. In 2014 SPD plans to construct the surface facilities and ASP injection is expected in 2015.
The paper focuses on the current status of the ASP pilot project. The objectives of the pilot are to demonstrate the oil recovery potential of ASP technology and collect enough information for decisions on the subsequent commercial stage. The pilot surveillance program, the surface facilities and the subsurface configurations were specifically designed to meet these objectives.
In this paper our recent progress on optimization of chemical formulation is also discussed to demonstrate how the properties of chemical ingredients of an ASP flood are influencing the design of the surface facilities. Different design options for the key elements of the surface facilities were evaluated emphasizing the role of process requirements determined by properties of the chemicals used, as well as logistics and the harsh weather conditions.
West Salym reservoir rock and fluid properties are typical for West Siberian oil fields. Hence, success of this ASP pilot project could pave the way for subsequent ASP projects in other West Siberian oil fields and have significant impact on the Russian oil industry.
Lessons Learned from Applying Particle Gels in Mature Oilfields
Authors: Qiu Yue , Wu Fengxiang , Wei Mingzhen , Kang Wanli , Li Baohong 
Published: June 2014

Abstract
As an effective conformance control method, gel treatments have been applied widely in mature oilfields to reduce excess water production by preferentially plugging the water thief zones after long-term water flooding. Performed particle gels (PPGs) are becoming more and more popular in China for this purpose because they overcome some of the inherent drawbacks of in-situ gel systems, including the lack of control over the gelation time, gelling uncertainty due to shear degradation, chromatographic fractionation or change of gelant composition, and dilution by formation water. However, the literature in this area remains limited, providing few case studies or data analyses regarding the use of PPG in oilfields.
This paper reports field applications of particle gels in water flooding, polymer flooding and ASP flooding. In Chinese oilfields from 2001 to 2012, we treated 655 wells with 12,765.62 tons of particles; the injected dry particles typically weighed between 11.5 to 20.6 tons per well. The applications covered both sandstone reservoirs and naturally fractured reservoirs with different temperatures and formation salinities. Properties of the particles applied in oilfields, such as the particle size, swelling ratio, and thermal stability, were tested. Eight cases are reported in this paper as examples of how to design and evaluate gel treatment projects. The results showed that the oil production rate increased from 14.3% to 50% and that water production decreased to the range of 0.4% to 4.7% after treatment.
Based on the case study, highlights of illustrative PPG field applications and results are presented. Criteria for well selection and PPG treatment design are provided to serve as a guide for the kinds of conditions under which PPG conformance control can be applied successfully.
Microemulsion Phase Behavior Measurements Using Live Oils at High Temperature and Pressure
Authors: Jang Sung Hyun , Liyanage Pathma Jith , Lu Jun , Kim Do Hoon , Pinnawala Arachchilage Gayani W.P. , Britton Chris , Weerasooriya Upali , Pope Gary A. 
Published: June 2014

Abstract
Microemulsion phase behavior is the most important phenomenon related to any type of chemical EOR using surfactants. Although the impact of solution gas and pressure on microemulsion phase behavior has been studied for decades, only a very limited amount of data are available in the literature and this is especially true at high temperature and pressure, nor is there a good theory available to guide our understanding of this behavior. A very large number of new chemical EOR projects are underway and almost all of them now involve live oil whereas in the past most of the projects did not involve live oil. The availability of sapphire view cells rated to 150 °C and 5000 psi has greatly extended our laboratory capability to do live oil studies under conditions where almost no data exist. These view cells allow us to make visual observations very similar to the critical phase behavior observations that we routinely make using glass pipettes at low pressure. For example, the classical emulsion test can be performed to qualitatively estimate the interfacial tension and viscosity. Also, it is easy to observe phase separation of the microemulsion/water/oil mixtures, the oil and water solubilization ratios and the equilibration times. This can be done using multiple cells so that salinity or other key parameters can be varied to determine optimum salinity and other key design parameters. This has allowed us to perform more tests at higher temperature and pressure with higher solution gas ratios than previous tests. The results are highly significant with very important implications for field applications to live oil reservoirs. Specifically, we have found the optimum salinity is closer to the dead oil than expected and higher than the value for surrogate oils made based on the equivalent alkane carbon number approach. The development of formulations that meets the aqueous stability criterion at optimum salinity is therefore more challenging than previously realized.
Dynamic Interfacial Tensions and Contact Angles of Surfactant-in-Brine/Oil/Shale Systems: Implications to Enhanced Oil Recovery in Shale Oil Reservoirs
Authors: Mirchi Vahideh , Saraji Soheil , Goual Lamia , Piri Mohammad 
Published: June 2014

Abstract
Unconventional shale oil resources have emerged as a significant source of fossil fuels in recent years. The oil contained in shales is held in natural microfractures, micropores, and inside nanopores of the organic matter. The strong capillary forces in these pores can bind the oil to the surface with strengths that are inversely proportional to the pore radius. In order to recover more oil from these pores, it is beneficial to reduce the capillary pressure by manipulating the interfacial tension and contact angle of oil/brine/shale systems using surfactant solutions. The main consideration in surfactant flooding is to optimize brine salinity and surfactant concentration while minimizing their adsorption on rock surfaces. Although the effect of some surfactants on recovery in shale oil reservoirs has been studied in the past, the mechanism is still unclear. Moreover, the limited data available in the literature is not representative of the actual reservoir conditions.
The objective of this study is to elucidate the oil displacement mechanisms in shale oil by surfactant flooding. The phase behavior of several anionic surfactants was studied in the presence of crude oil at reservoir temperature (i.e. 80 °C). The results of these tests were used to screen the best surfactants. Dynamic interfacial tensions (IFT) and contact angles (CA) of selected surfactant-in-brine/oil/shale systems were measured by the rising/captive bubble technique using a state-of-the-art IFT/CA apparatus. The apparatus was thoroughly validated with various systems using the axisymmetric drop shape analysis technique. Using the same methodology, the effects of surfactant concentration (0.01 to 0.1 wt%) and brine salinity (0.1 to 5 M NaCl) on IFT and CA at ambient and reservoir conditions (i.e. 80 °C and 3000 psig) were studied. Surfactant adsorption on shale samples was also measured in brines at ambient conditions. Our data reveal that the most effective surfactant was able to reduce the oil-brine IFT from its original value (23 mN/m) down to 0.3 mN/m at reservoir condition. A reduction in the IFT value and an increase in the dynamic contact angle of oil drop on polished shale surface were observed with the addition of surfactant and salt to the system. A trend between these parameters, pressure, and temperature was also reported.
Drilling Depleted Reservoirs using Controlled Mud Level Technology in Mature Subsea Fields
Authors: Fossli Børre , Stave Roger 
Published: June 2014

Abstract
Many subsea fields on the NCS are now entering maturity. As reservoir pressure declines, this inherently introduces significant well construction and well delivery challenges. Wells are the biggest driver for increased recovery. Depletion and increased formation pressure heterogeneity in mature fields are driving costs and slowing well delivery. For fields developed with fixed platforms, conventional pressurized Managed Pressure Drilling (MPD) techniques developed on land has been used for some time to combat these challenges. For floaters with subsea Blow Out Preventers (BOPs) and Low pressure marine drilling risers in harsh environment, other technologies are needed. EC-Drill is a new technology developed by AGR Enhanced Drilling specifically for floaters which will regulate the drilling fluid level in the marine riser in order to manage the wellbore pressures. A subsea mud pump is connected to the marine drilling riser and is used to manage the fluid level within the riser up or down. The drilling fluid is pumped back to surface from a lower level on the riser so that the hydrostatic pressure in the wellbore can be managed more effectively. This also enables using conventional mud weight to drill depleted reservoirs. The technique also allows for precise control of wellbore pressures and enables drilling with close to constant bottom hole pressure. The technology will ensure improved hydraulics which can result in; improved hole cleaning, higher rate of penetration, improved casing/liner cementing, less downtime (NPT) due to formation pressures heterogeneity and longer horizontal sections may now be drilled in depleted reservoirs, etc.
This paper discusses the challenges related to drilling in depleted reservoirs and outline the new drilling technique that is available to solve these and other drilling challenges on the Norwegian Continental Shelf (NCS).
High Quality Flow Information from Tracer Data
Authors: Huseby Olaf , Hartvig Sven K. , Jevanord Kjersti , Viig Sissel O. , Dugstad Øyvind 
Published: June 2014

Abstract
This paper describes a systematic methodology to extract as much information as possible from inter-well tracer tests. Interwell tracer testing has been used extensively in Norway and world-wide the last 2-3 decades and is proven as an efficient technology to map well-to-well communication and sweep, and to evaluate the effect of water and gas injection projects.
Significant information can usually be extracted from tracer curves, in addition to the immediate injector-producer communication available upon first tracer breakthrough. Improved tools and methods, such as residence time distribution (RTD) analysis, can quantify how effective water and gas floods displaces water, and reveal flow paths and channels prior to infill-drilling, polymer blocking etc.
However, prior to interpretation of tracer data, it is essential to remove uncertainties due to water or gas re-injection, commonly applied to reduce discharge to the environment and save scarce water-resources. However, recirculation of produced water and gas can be seriously misleading when tracer data are interpreted, because tracers will be re-injected with re-injected water or gas.
In this paper we show how the background tracer concentration due to re-injection can be removed in a systematic and unambiguous manner. The methodology is tested on data from tracer campaigns in two field cases. The tracer data from the field cases are subsequently used to evaluate water flooding sweep and reservoir heterogeneity using residence time distribution (RTD) analysis. The field case results show that the method is well suited to obtain quantitative flow pattern information from tracer data, and provides an effective tool for reservoir engineers that use tracer data to extract information about reservoirs.
Collecting Large Sample Volumes While Drilling With Minimal Contamination
Authors: Cartellieri Ansgar , Tran Pei-Chea , Galvan-Sanchez Francisco 
Published: June 2014

Abstract
Acquiring samples earlier in a well plan minimizes reservoir uncertainty and enables better planning for future activities. The deployment of a logging while drilling (LWD) fluid analysis and sampling tool in this scenario enables the operator to mitigate the risk of data acquisition and improves access to challenging boreholes including deviated wells and extended reach drilling.
This paper discusses the deployment of a LWD formation pressure testing and sampling tool in a high angle well in Asia Pacific. The objective was to collect representative gas samples for geochemical analysis and proper facilities design. Therefore large representative sample volumes of up to twenty liters were required to ensure a proper lab analysis of the reservoir fluid properties. These samples were taken in two different wells during dedicated sampling while drilling runs.
The highest priority was maintaining the chemical composition of the sample as close to in-situ condition as possible. Consequently, a minimized chemical adsorption within the tool's metallurgy was required. Although the metallurgy of the tool and the tank systems are inert to adsorption of most geochemicals in reservoir fluids, it was decided to apply a coating to some of the tanks.
The contamination level during the clean-up process while sampling gas is difficult to predict because an emulsion may be generated that masks the clean-up response and gas signature of the sensors during fluid analysis. One of the recent improvements to the LWD fluid analysis and sampling service is real time mobility and compressibility measurement. These two measurements are solely based on the pump system and not adversely affected by immiscible fluids. It will be discussed how the clean-up process can be improved furthermore without adding tool functionality and increasing the service complexity.
The Effect of Peroxide Concentration when Removing Iron from Brine: A Kinetic Study
Authors: Patil Anil , Managave Pallavi 
Published: June 2014

Abstract
High-density completion brines are widely used in well completion and workover operations. However, these high-density brines are susceptible to iron contamination and thus must be treated for iron removal. In particular, high-density brines containing zinc are the most difficult to treat for iron removal due to their relatively low pH.
Multiple approaches and technologies have been used for brine reclamation, including the use of an oxidizing agent such as peroxide. Unfortunately, conventional reclamation processes using peroxide usually require multiple steps, significant chemical additions, long reaction times, and extensive filtration to remove the iron and the excess treatment chemicals. However, it has been observed that using a higher concentration of peroxide can quickly and effectively remove iron even from brines containing zinc.
This paper describes the effectiveness of various peroxide concentrations used to remove iron from zinc bromide and calcium bromide brines. In a laboratory experiment three concentrations of hydrogen peroxide (0.6%, 1.5%, and 3%) were tested for their ability to remove iron from these two brines over various time intervals. The 0.6% peroxide reduced the iron concentration in the zinc bromide brine by 24% in 48 hours. Increasing the hydrogen peroxide concentration from 0.6% to 1.5% resulted in a 98% reduction of iron in 48 hours. However, maximum effectiveness was achieved with a 3% hydrogen peroxide concentration, which reduced the iron by 100% in just 6 hours. Experiments performed on calcium bromide brine showed similar results.
A kinetic study shows that the reactions follow first order kinetics. From the standpoint of kinetics, we calculated the initial rate of reaction for each concentration of peroxide which proved that the reaction rate increased as the peroxide concentration increased. For the 0.6% hydrogen peroxide concentration, the calculated rate constant was 3x10-6S-1 with the half-life of 64.16 hr. For the 3% hydrogen peroxide concentration, the rate constant was calculated as 2x10-5 S-1 and with a half-life of 5.2 hrs. In addition, we calculated the activation energy for each of the reactions which are detailed in the paper.
Electric Line Riserless Light Well Intervention (RLWI) Methods Key to Increasing Recovery from Subsea Wells
Authors: Karlsen Ole Eddie , Andrews Garry 
Published: June 2014

Abstract
The number of subsea wells has increased steadily and by the end of 2012 exceeded 5,500 (Infield 2013). These wells pose a number of challenges including generally lower recovery factors compared to wells with surface access. The high operating rates of rigs have had a natural damper on the incentive to increase recovery rates, as the balance between cost and revenue has been unfavorable—even with increasing oil and gas prices. However, this has also spurred the drive to develop alternative methods to enhance recovery and cope with the challenges of maturing fields and exploration under more difficult circumstances.
Adopting frequent lightweight well intervention has proven crucial for subsea operators to realize the potential of 50% oil recovery. Such operations are becoming more common, but there are increasing challenges and demands as development moves toward deeper waters. To reduce overall risks and use the natural resources more effectively, new technology and improved operational efficiency are required. The ability to carry out frequent, scheduled interventions as opposed to remedial interventions is fundamental to raising recovery rates.
Lightweight and riserless well intervention has proven its potential for driving improvement in recovery rates. The ability to substitute rigs with smaller, dynamically positioned light well intervention vessels has a major impact on cost and scheduling. Electric line (e-line) Riserless Light Well Intervention (RLWI) has demonstrated its value and the fact that it is an inherently safer method for intervening on subsea wells compared to conventional, heavier methods using a riser.
This paper gives a detailed account of the opportunities to improve recovery rates in subsea wells by having access enabled with this lighter, more efficient, and ultimately more productive intervention method. Several case histories and examples will be shown.
World's First Hydrate Plug Milling on E-Line
Authors: Karlsen Ole Eddie , Skeie Terje , Buch Jorgen , Keith John 
Published: June 2014

Abstract
Operators often struggle with a complex phenomenon causing unwanted and often unpredicted hydrate plugs to form in producing or injection wells, blocking production and re-entry to the well. Conventional remediation methods can be costly, time consuming, and are often ineffective.
This paper will share the knowledge gained from a world's first operation, demonstrating that hydrates can be milled using electric line (e-line) tools. The operation was performed from a Vessel Fit for Purpose (VFFP) as a Riserless Light Well Intervention (RLWI) operation in the North Sea, offshore UK.
A hydrate plug was tagged below the subsea tree in a water injection well. This unconventional solution was chosen to restore injectivity to wellbore and minimize non-productive time (NPT). Unfortunately, during the operation, harsh weather caused operations to be stopped due to safety issues, and prevented removal of the entire hydrate plug. At that point, reestablishing functionality to the downhole safety valve became a major issue. Fortunately, in less than 20 hours of milling time 173 ft (52 m) of hydrates were removed on e-line and the operator was able to re-establish the functionality of the downhole safety valve.
E-line technology provided a swift and accurate resolution to the problem, proving that hydrates can be dealt with as easily as doing any other e-line intervention and that the technology can be run in a ‘live’ well under pressure.