bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Research Model for Using Sacrificial Agents to Enhance Surfactant Performance in Liquids Rich Shale Reservoirs
Authors: He Kai , Xu Liang 
Published: March 2016

Abstract
Post-fracturing production data analysis indicates stimulation of some west Texas wells with surfactant additives did not enhance production as high as expected. Analysis of flowback and produced water for surfactant residues revealed 99% of surfactant was retained inside wells (Rane and Xu 2015). This indicates surfactant plating out on rock in the near-wellbore (NWB) region, restricting travel deeper into the reservoir, which compromises well performance. This study presents a sacrificial agent (SA) to cover rock surface near the wellbore, allowing surfactant to penetrate the formation.
Literature precedent exists that polyelectrolyte (PET)-based SAs could significantly reduce surfactant adsorption not only onto a variety of outcrop minerals (Carlpool dolomite, calcite, kaolinite, Berea sandstone, Indiana limestone, etc.) and metal oxide nanoparticles, but also unconventional shale formulations in which surface area can be up to 700 m2/g. In this study, the adsorptions of surfactant and SA to proppants were first examined. Results indicate no adsorption was observed to proppant for both surfactants and PET-based SAs. SAs (0.5 to 1 gal/1,000 gal (gpt)) were then injected with surfactant (1 to 3 gpt) at an appropriate ratio into column-packed shale formulations (primarily composed of calcite, dolomite, quartz, illite, pyrite, and plagioclase feldspar) to investigate its effectiveness in controlling surfactant retention caused by adsorption. Laboratory testing revealed injection of 3 gpt mixture of surfactant and SA has a similar adsorption profile (surface tension as a function of time) as 3 gpt surfactant alone based on the dynamic surface tension measurement. Notably, the addition of SAs resulted in lower surface tension and enhanced hydrocarbon solubility; and thus, an improved oil recovery by surfactant was achieved as evidenced by the oil recovery tests. Additionally, 68% friction reduction of the fracturing fluid with surfactant and SA was sufficient for the field operation compared to the guar-based fluid used in the hydraulic fracturing applications.
As a result of the laboratory findings, field trials were executed on a three well pad in the Permian basin (PB). For the first 30 days oil and gas production appeared to be significantly higher than the average production from offset wells in the same area that were previously fractured with the same surfactant.
Effect of Heterogeneity on Propagation, Placement, and Conformance Control of Preformed Particle Gel Treatment in Fractures
Authors: Imqam Abdulmhsin , Wang Ze , Bai Baojun , Delshad Mojdeh 
Published: March 2016

Abstract
Preformed particle gels (PPG) have been successfully applied as a plugging agent to solve the conformance problem in fractured reservoirs. They are injected to plug fractures and then divert displacing fluid into poorly swept zones and areas. However, PPG propagation and plugging mechanisms through open fractures have not been studied thoroughly. This paper investigated the influence of some factors (particle size, brine concentration, heterogeneity, injection flow rate, and brine salinity) on gel injectivity and plugging performance for water flow through opening fractures. Five-foot tubes were used to mimic opening fractures. Three models were designed to gain understanding on how fracture geometry and PPG properties affect gel injection and plugging efficiency, including (1) single fracture with uniform fracture width, (2) single fracture with different widths, and (3) two parallel fractures with different width ratios between each other. Results from single uniform fracture experiments showed that PPG injection pressure was more sensitive to gel strength than gel particle size. When large PPG size and high gel strength were used, high injection pressure and large injection pore volume were required for PPG and brine to reach fracture outlets. Results from single heterogeneous fracture model experiments showed PPG injection pressure increased as the fracture heterogeneity in sections increased. Particle gel accumulated at the choke point within each fracture and caused injection pressure to increase accordingly. Furthermore, results showed that having a lower salinity within a fracture, which was less than the brine salinity that was used to prepare PPG, would improve the PPG plugging efficiency for water flow. Parallel fracture models results showed that when weak PPG was used, a large volume of PPG flowed into a large fracture width and a small portion of the gel particle volume flowed into small fracture width. However, with increased gel strength and fracture width ratio, PPG only flowed through larger fracture widths. This paper demonstrates important impact elements of gel propagation and water flow for different opening fracture situations.
Dynamic Attributes for Characterization of Complex Oil Reservoirs, A Case Study from R. Trebs Oil Field, Timan-Pechora Basin, Russia
Authors: Shumatbaev K. , Privalova O. , Gainullina E. , Akhmetzyanov R. , Chervyakova A. , Melnikov A. , Fedorov A. , Kuchurina O. 
Published: March 2016

Abstract
The paper presents the void space configuration and geometry models for the Lower Devonian and Upper Silurian reservoirs of R.Trebs oil field. The productive formations are characterized by heterogeneity and complex architecture of the pore space which includes practically all types of voids – primary and secondary or epigenetic pores, fractures and solution vugs developed along fractures. The study reviews small to large scale methods for analysis of vug component as a fraction of the void volume in the reservoirs – laboratory (thin sections, conventional core plugs and whole or full-diameter core samples), rock physics (sonic waveform logging, nuclear magnetic resonance, imagers) and production logs (flow profile, productivity). The results are used to develop simplified models for reservoir characterization of the pore space architecture for the Lower Devonian and Upper Silurian productive formations and also to identify trends in well productivity as a function or rock physics properties of the reservoirs.
New On-Command Integrated Under Reamer Elevated Drilling Performance, Reduced Operational Risks and Lowered Cost: A Case Study in the Oseberg South Field
Authors: Ahlberg Jill , Fang Lei , Hoff Kjell Rune , Manseth Arvid , Schwartze Sascha , Larsen Johan Fredrik , Borlaug Kjetil , Longvastøl Karl Gerhard 
Published: March 2016

Abstract
This paper presents technical features and associated benefits of a recently developed under reamer technology and its applications in the offshore Norway Oseberg South field to drill 12 ¼″ × 13 ½″ and 8 ½″ × 9 ½″ sections. It discusses the results of the operations and demonstrates how the operations benefited from the new technology.
In today's drilling operations, expandable reamers are broadly used to support optimized casing and completion programs and to reduce operational risks such as high Equivalent Circulating Density (ECD), drilling troublesome formations and reaming well path conformities. The currently available hole enlargement technologies, such as ball drop and hydraulically activated reamers, carry intrinsic risks and limitations.
To address the challenges associated with currently available under reamer technologies, expandable reamer technology was recently developed jointly by a service company and a major operator, and was field tested offshore Norway. The under reamer, which is fully integrated with the company's existing Rotary Steerable System (RSS) Bottom Hole Assembly (BHA), provides unlimited, on-command activation cycles, optimal placement within the BHA in multiple configurations and real-time feedback via mud-pulse telemetry. The feedback from the reamer includes confirmation of blade activation status, health of the tool, and vibration and stick-slip measurements. Because of the flexibility of its placement in the BHA, the reamer can reduce the length of the rat hole to a minimum of 4 m compared to the standard 30 to 70 m in the same drilling run, eliminating the need for a dedicated clean-out run. The reamer also enables reliable and unlimited activation / deactivation cycles with each cycle taking less than 5 minutes, saving operational costs for the operators.
The under reamer was successfully deployed to drill challenging 12 ¼″ × 13 ½″ and 8 ½″ × 9 ½″ sections in the offshore Norway Oseberg South field. The 2497 m long 12 ¼″ × 13 ½″ section and 900 m long 8 ½″ × 9 ½″ section were both drilled to Total Depth (TD) in one run, with all requirements on directional control and Measurement While Drilling (MWD) / Logging While Drilling (LWD) met. The technology was proven to be a reliable and flexible hole enlargement while drilling solution that elevates drilling performance, reduces operational risks and lowers operational costs.
Production of Sedimentary Methane Hydrates by Depressurization
Authors: Almenningen Stian , Flatlandsmo Josef , Fernø Martin A. , Ersland Geir 
Published: March 2016

Abstract
The voluminous amounts of hydrates found in nature are distributed across all continents and pose a huge possibility for future energy harvest. In fact, the total amount of energy stored in hydrates is predicted to be in the same range as conventional fossil fuels combined. Successful exploitation of this energy supply will serve as a vast and relatively clean source of fossil fuel for the remaining of the fossil era. Natural gas hydrates consist of guest molecules encapsulated inside cavities formed by hydrogen-bonded water molecules. The origin of the encaged gas may be biogenic or thermogenic with methane being the most common hydrate former in the earth. Methane hydrates are stabilized at elevated pressures and low temperatures and are mainly located in onshore permafrost regions and in marine sediments offshore.
This paper review how production of methane from hydrates can be triggered by dissociation of the hydrate structure. Techniques leading to dissociation of hydrates are summarized by pressure depletion, thermal stimulation and injection of inhibitors. Depressurization is considered to be the most cost-effective method and is easily implemented in gas reservoirs with overlying hydrate layers. Examples and status of pressure depletion tests on field scale will be reviewed. In hydrate reservoirs not adjacent to gas zones, the success of pressure depletion is dependent on sufficient permeability to allow for pressure perturbations to reach within the hydrate reservoir and to allow for flow of dissociated gas. This effect has been investigated in this paper by performing controlled pressure depletions on hydrate-filled sandstone cores. Dissociation pressures at given temperatures have been quantified as well as recovery of methane as function of pressure-decrements below dissociation pressure. A 2D porous silicon wafer micromodel was used to gain insight on the mechanisms of hydrate dissociation. Direct visualization of hydrate melting induced by both depressurization and heating is reported from pores replicating authentic sandstone pores.
Innovative Concepts in Wireline Continuous Coring
Authors: Ashena Rahman , Vortisch Walter , Prohaska Michael , Thonhauser Gerhard 
Published: March 2016

Abstract
Coring in unconventional reservoirs with typical unconsolidated formations has introduced additional challenges requiring more innovative concepts to be developed. These requirements, economic issues of unconventional reservoirs, and also issues of conventional coring particularly in regard to excessive trip times incurred have recently led to widespread attention to wireline continuous coring (WCC) modified from mining industry to petroleum industry applications. This coring method has contributed to coring deep formations, long core sections, multiple zones, jam prone formations, exploration zones or areas with unknown core points. Currently, WCC is suffering from several drawbacks while some recent attempts have been made to remove them. In this accordance, this work is missioned to remove some existing defects by adding some innovative concepts to be applied to the ordinary WCC. Therefore, a more efficient continuous coring method is aimed which includes enhanced coring key performance indicators.
Therefore, several identified challenges of WCC are considered to be removed or alleviated by innovative concepts to be added. The challenges consist of un-flushed inner tube while run in hole, limited retrievable core size, in-situ/pressure coring hazards (i.e. safety issues, complex sealing, etc.), slick line issues (rig time, torque, rupture, etc.), untimely and inefficient decision making while coring/drilling, non-optimized coring/drilling and tripping induced core damage in WCC.
In order to address these issues, as novelty measures, first an inner tube flushing system is proposed for flushing inner tubes prior to commencing coring. Second, casing drilling coring is recommended in order to obtain larger core sizes contributing to improved core analysis. Third, in-situ downhole measurement and sampling systems are proposed to measure properties of in-situ fluids in order to complete or replace pressure/in-situ coring systems and ensure safety. Fourth, an innovative mode conversion system is proposed to mitigate slick line issues. Fifth, a less complex logging while coring system has also been proposed in special cases to enhance and expedite real time decision making process in regard to proceeding to core cutting or not. Sixth, an innovative mode conversion system contributing to partial elimination of wireline jobs will also be proposed to substitute slick line/ wireline retrievals. Seventh, optimum tripping schedules have been characterized as crucial to match formation rock and fluid properties and type of WCC applied and also to prevent coring induced damage.
Subsea Blowout Source Control Technologies Utilized at the Macondo Accident and Developments in the Post-Macondo Era
Authors: Kutas David Thomas , Bailey Philip , Prohaska Michael 
Published: March 2016

Abstract
The publication generally and briefly describes what circumstances governed the petroleum industry and the connected regulatory organizations before the Macondo blowout. The paper shortly describes utilized classic containment and control efforts such as actuation attempts of the BOP, top kill with junk shot, relief wells. The publication's main focus is to describe and graphically present in detail the Cofferdam, the Riser Insertion Tube Tool, Top Hat, Capping Stack and choke and kill line collection method which were utilized to seal off the flow of hydrocarbons at the Macondo blowout. An extended literature review has been completed to fully cover and understand the technologies which were utilized and newly developed in the efforts to stop the outflow and abrogate the accident. The assessment of critical properties, problems are also presented next to the description of the specific source control technology. The blowout has triggered efforts never seen before both in short- and long-term not only from the side of affected regulatory and company side but industry wide. Short-term, the main effort was to contain the blowout as soon as possible, long-term it triggered strong determination from companies, and connected businesses to create proper contingency planning, containment technologies and strategies also through newly established consortiums. The non-profit oriented consortiums, containment systems and established HSE regulations need to be maintained properly even in a low oil price environment, so deeper understanding, recurrent inspection of the development ways of containment technologies in offshore environment can be crucial for sustaining the high HSE standards. The paper also aims to summarize knowledge to be able to make proper decisions in case of deepwater projects.
Taming the Beast: Consideration of Available Surface Power When Using a Modern, High-Specification Rig
Authors: Snowie Mike , Alemi Hassan 
Published: March 2016

Abstract
Modern Mobile Offshore Drilling Units (MODU) are equipped to ensure they are able to cope with the demands of both current and future offshore well design challenges which may be located in either in deep water or inmature basins like the North Sea thatrequire significant measured depths to reach the intended target. With all of this drilling power, such as topdrives capable of producing over 75,000ft-lbs of continuous torque and multiple mud pumps each with the ability to flow in excess of 1,000gpm it is readily possible to damange the wellbore by over using the available capacity of the rig. In reality this surfeit of available energy, if not used judiciously, can potentially result in unexpected problems.
Much has been written in the past with regards to ensuring that the available rig capability is best utilised to achieve complex well objectives and a great deal of the techniques developed in extended reach and complex well drilling operations were designed to make the most of the capacity available. Now, with high specification rigs these techniques identified originally in the early to mid-1990's, though still valid need to be used with care and consideration since the rig capabilities have advanced significantly such that without a degree of caution it is possible to cause significant damage to the downhole tools or wellbore and potentially loose either the section or the well altogether. Whilst many of the techniques often termed ‘good oilfield practice’ are still valid there are now additional considerations which have to be incorporated into both the well plan and the day-to-day operations on the rig to ensure that best use can be made of the rig's capability.
This paper aims to show how one operator successfully used a modern, high-specification jack-up rig to access a remote reservoir where challenging drilling conditions presented a number of potential obstacles to achieving the well objectives.
Effect of Rheology on Annular Sealing: From Placement to Failure
Authors: Lavrov Alexandre , Torsæter Malin 
Published: March 2016

Abstract
Wellbore integrity is a crucial aspect of well construction. The integrity of annular sealing has a bearing on the overall integrity of the well. The integrity of the annular seal is affected by the properties of cement (or sealant, in general), including its permeability, mechanical strength, bonding strength, chemical and thermal stability. Well integrity is also influenced by large defects introduced into the sealant during placement, e.g., gas channels caused by gas migration during setting, or mud pockets left undisplaced in washouts.
The displacement efficiency is a function of the mobility ratio of the fluid in place, e.g., the drilling mud, and the fluids being injected, such as the spacer and the cement. Rheological properties of the fluid in place and the injected fluids, the well inclination, and the geometry of the annulus have an impact on the displacement efficiency.
The effect of rheological properties of the injected fluid and the fluid in place (yield stress and the plastic viscosity) is evaluated in this study by means of numerical modeling. It is shown how a proper combination of the rheological properties can improve the fluid displacement from constrictions in the annulus, e.g., when the casing is not perfectly centralized in the borehole. It is also shown how an unfavorable combination of rheological properties and annular geometry may promote the development of gas channels and mud pockets in the annulus. Unless the borehole cross-section is perfectly circular, an unfavorable combination of rheological properties may lead to viscous instabilities during annular flow, resulting in mud channels left in the annulus. During lifetime of the well, such channels may become conduits for formation fluids. They also may serve as stress concentrators when in-situ stresses or wellbore temperatures are altered. Finite-element computations of thermal stresses near a channel left in the cemented annulus reveal that tensile stresses induced around such a channel by heating may be sufficient to create fractures in cement around the channel.
The methodology elaborated in this study enables prediction of cement integrity from placement to failure and thus spans the entire well lifetime.
Workflow for Optimal Injection of CO2 to Enhance Oil Recovery in Mature Oil Fields: A Preliminary Study for a Field Pilot Program
Authors: Alcorn Zachary P. , Fernø Martin , Graue Arne 
Published: March 2016

Abstract
Enhanced oil recovery (EOR) from mature oil fields presents unique challenges, as it requires well designed workflows for the injection of water, gas, or chemicals. Determining the optimal injection and production plan for mature fields can both maximize hydrocarbon recovery and reduce cost. This study proposes an integrated reservoir management workflow to improve oil recovery in mature oil fields in an ongoing field pilot research program. The workflow involves integration of traditional reservoir management methods with a real-time optimization approach. The early phase pilot research program management strategy is composed of several key components, including: improved reservoir characterization, generation of reservoir and simulation models, history matched simulation models, and development of a real time approach to optimize EOR reservoir peformance. The optimization strategy allows decision making at two different time scales: coarse and fine. At the coarse time scale, decisions are made about monthly injection and production rates over a time horizon from the decision making point into the distant future, aiming to optimize net present value (NPV). Various economic and technical constraints are included at both time scales. Field data from a conjoined five-spot well pattern, with two injectors and six surrounding producers, in a heterogeneous carbonate reservoir in the Permian Basin of west Texas is considered. Several realizations of a reservoir model were history-matched to field performance and subsequently used to predict and optimize future performance. The proposed workflow is being adopted within a current field pilot research program. The implementation of such a reservoir management plan allows operational decision making to be better informed and updated in real time. Assimilation of newly obtained data removes the cumbersome task of manually updating reservoir models to forecast field operations.
Four Years of Continuous Foamer Application in Southern North Sea Offshore Gas Wells
Authors: Vogelij Nico A. , Veeken Cornelis A. , Islamov Rafael I. , Lugtmeier Bert , Ros Oscar , De Vries Gert , Zhidkova Natalia A. 
Published: March 2016

Abstract
In the current brown field environment a lot of mature gas wells in the Southern North Sea (SNS) are liquid loading. Foamer can be injected in the wellbore as a gas well deliquification (GWD) measure to mitigate this liquid loading behavior. Foamer can be injected periodically in batch mode or continuously downhole by means of a small capillary string installed in the wellbore.
To date ONEgas* is producing 12 offshore gas wells located on 3 manned SNS platforms by means of continuous foamer (CF) injection. The first offshore CF installation came online in 2011 and dozens more installations are scheduled in the near future. CF has gone through a steep learning curve where the next step is to install CF on an unmanned SNS platform. After 4 years of gas production with CF a lot has been learned about designing, installing and operating capillary string CF installations.
This paper demonstrates the success of continuous foamer injection by showing increased production and recovery due to foamer but also presents the challenges that were experienced in terms of uptime i.e. poor reliability due to capillary blockages, sand erosion and surface facility upsets etc. The method of tackling these reliability issues to maximize uptime is presented, including an overview of the current and future subsurface and surface hardware components.
*ONEgas is a combined business unit of NAM and Shell UK