bluuebunny/crossref_metadata_2025_split huggingface dataset:
Integrating Broadband Seismic and CSEM to De-risk Exploration Targets
Authors: Kiyashchenko Denis , Fan Yuanzhong , Blades Dina , Geisslinger Axel , Hindriks Folkert , See Mark , Hazewinkel Jeroen 
Published: May 2016

Abstract
CSEM can be used as a tool for regional exploration. However, CSEM-based prospect screening may be often mis-lead by anomalies caused by tight sediments. Integration of acoustic impedance derived from broadband seismic and CSEM helps us to identify those false anomalies and highlight the ones being potentially related to hydrocarbons. We also develop the methodology of inversion-based quantitative interpretation for CSEM and Broadband seismic data in order to quantify hydrocarbon potential and Earth resistivity uncertainty.

Introduction
CSEM has been used extensively for de-risking prospects and is now rapidly emerging as a regional exploration tool that supports the detection of hydrocarbon formations. A key challenge with using CSEM for prospect identification is to differentiate HC related resistors from the non-HC related resistors and separate the "true positives" from the "false positives". Integration with other subsurface data, such as well logs, geochemistry and the seismic underpins joined interpretation, appropriate inversion for rock properties and, finally, PoS polarization. We build upon both regional CSEM and the latest broadband seismic data to achieve this goal.

Joint CSEM and Acoustic Impedance interpretation
High resistivity foremost indicates an absence of saline formation water and can be caused by tight formations, certain lithologies, low salinity aquifers or hydrocarbon presence. Seismic data provides information on the acoustic properties of the sediments, which can be related to burial, uplift, fluid fill and overpressures for typical lithologies in Brunei acreage. For brine-saturated sands, Archie law can be used to relate electrical resistivity and acoustic impedance to porosity (see Figure 1).
Multiscale Simulations of Fluid Flow in Nanopores for Shale Gas
Authors: Umeda Kazuki , Li Rongjuan , Sawa Yunosuke , Yamabe Hirotatsu , Liang Yunfeng , Honda Hiromi , Murata Sumihiko , Matsuoka Toshifumi , Akai Takashi , Takagi Sunao 
Published: May 2016

Abstract
Advanced microscopy and image analysis techniques revealed that massive nanpores exist in shale gas formations. The process of the microscopic gas transportation from nanpore systems (of shale) and the macroscopic produciton from shale gas reservoirs needs to be better understood. Here, we developed a multiscale simulation scheme for studying gas flow in nanpore systems using molecular dynamics (MD) and lattice Boltzmann method (LBM). MD is a powerful technique by which we can get thermodynamic properties of the simulation system at desired temperature and pressure, and simulate the gas flow in molecular scale. By this computational method, we will investigate transportation characteristics of methane molecule in molecular scale and estimate the slip velocities fordifferent solids at different temperatures and pressures. LBM, on the other hand, is a computational method for continuous fluid dynamics. In enables us to upscale MD simulation results from molecular scale to pore-scale with complicated geometries, and estimates the permeability to taking consideration of the slip velocities.
First, we calculated the mean free path and slip velocity, and evaluated the slip velocity as a function of Knudsen number using MD simulations. The MD simulations were conducted for three different constituents of shale nanpore surfaces; quartz, clay and kerogen at around 12 MPa and temperatore from300 K to 400 K. The fully hydroxlated α-quartz (001) surface, which contains vicinal silanol, was employed as a model of quartz system. The uncharged pyrophyllite surface was employed to represent a model of clay. The shinn model (Type III) kerogen slab was employed as a model of organic rich shale.
Second, we implemented the slip velocity obtained from MD simulations in LBM simulations. As for the fluid-solid boundary, we adopted counter slip boundary condition, which enables us to configure the slip velocity at the wall so as to satisfy that obtained from MD simulations. Then, we simulated the gas flow in nanpores with different pore geometries. For a simple slit geometry, it was found that the slip flow induced high permeability, which is about 0.1–1.8 times of that for non-slip flow. For systems with complicated geometries, we demonstrated that permeability of slip flow can be estimated from the pore profile. The application of multiscale simulation scheme to a more realistic system is straightforward.
Enhancing Business Performance through Collaboration and Fast Decision Making
Authors: van den Berg Frans 
Published: May 2016

Abstract
Collaborative Work Environments (CWEs) have provided significant benefits to Shell in production, field management and maintenance. The CWEs enable faster and better decision making by improved communication and easier sharing of relevant information and data. Business benefits include increased production, higher equipment reliability, lower operating cost and improved HSE. Considerable learning was derived that helps future implementations and ensures sustainability.

A Global CWE Programme
Around 2005, Shell began the journey to enhance collaborative working within its producing assets (Knoppe 2008). Today the advantages of working in a collaborative environment are well understood and the concept is widely embraced throughout the petroleum industry (e.g. Gilman 2012).
Shell embarked on a large-scale implementation in all its major assets around the world since 2011, under drive from the global production leadership. This forms part of the global Smart Fields programme (De Best 2012, Van den Berg 2010). Many CWEs are now in place (Fig. 1), by 2015 more than 60 Shell assets will have over 400 live CWE rooms. The global implementation programme has enabled achieving these benefits faster, by creating a common methodology, standardising technical solutions, capturing lessons learnt and transferring the knowledge and best practices to new assets. In addition, it has provided the business leadership a vehicle for standardising business processes in the many assets around the world.
New Inversion Method to Determine In-Situ Stress From Borehole Induced Fractures
Authors: Huang Jinsong , Wong Sau-Wai 
Published: May 2016

Abstract
The drilling induced tensile fractures can be observed from borehole image logs but they must be differentiated from natural fractures. This paper focuses on the understanding of hydraulically or artificially induced tensile fractures while drilling. We present an inversion method using rigorous principles of mechanics, to determine the in-situ formation stress state from observed induced tensile fractures. Contrary to common practices where only vertical or near vertical wells can be analysed, the present method is applicable to wellbores of all orientations. For a geological rock formation and area where the in-situ stress regime can be assumed to be similar, all the relevant borehole image logs can be included to provide information to yield the most probable subsurface in-situ stress state. The proposed inversion method directly solves for the in-situ stress states given any single set of observed tensile fracture location and orientation. It provides not only an estimate for the minimum horizontal stress magnitude and direction, but also the maximum horizontal stress magnitude which is usually very difficult to pin down. The resultant equations are non-linear and a simple numerical scheme is adopted for the solution. Although published data on borehole images of fractures with corresponding in-situ stress information are scarce, two observed field data from published papers are chosen for comparison.

Introduction
In-situ stresses in deep rock formations reached equilibrium over geologic time; but drilling, production and injection processes cause deformation in the rock mass and change these stresses, and often negatively impact the operator's development plan. If they are not well anticipated, the challenges and costs of managing a prospect can far exceed the initial field development expectation. Therefore, it is vital to characterize the undisturbed in-situ stress and evaluate potential impact of field development induced rock stress changes. Two examples that come to mind are 1) enhanced oil recovery field development where injection scheme takes place under hydraulic fracturing condition and 2), the development of unconventional resources such as shale gas, where the effectiveness of hydraulic fracturing to access hydrocarbon is impacted by the in-situ stress regime. The latter, for instance, is encountered in China's Sichuan basin where operators are striving to determine whether hydraulic fractures in certain areas of the basin are developed under thrust-faulting or reverse-faulting stress regime (Yuan et al, 2013). A reverse-faulting stress regime implies that the hydraulic fractures would grow in a horizontal 'pancake' fashion, diminishing its effectiveness in draining the reservoir.
Reviving Brown Field Oil Potential: Case Study of Multilayer Reservoir
Authors: Antariksa Zona Nuansa , Ultra Dian , Malau Aldani , Sukotrihadiyono Tejo 
Published: May 2016

Abstract
High demand and a significant increase in the price of crude oil have triggered the oil and gas industry to produce more oil and gas from their assets. Optimizing mature fields is one of the efforts that can be applied to increase production.
"RBT" field is located in South Sumatera, Indonesia, and was discovered in October 1972. It has produced from multilayer "PLB" sand reservoir since 1974. Originally this field was produced as an oil field, with a peak rate of up to 1630 BOPD, declining to 300 BOPD 9 years later. Thereafter the field was converted into a gas field producer with small condensate and is still producing now. Based on the above, it is very challenging to look for by-passed oil in "PLB" sands reservoir, since the production test data and history of this field are very limited, so the field can produce more oil and maximize the recovery factor.
This paper explains the steps that need to be taken to analyze by-passed oil in a multilayer reservoir, including: production data test review, surveillance data analysis, historical completion review, sand layer re-correlation, estimating update reservoir contact and updating geological map. After all of these steps have been completed, work over and well service jobs will be used to validate the analysis and evaluation, allowing further development strategy to be prepared.
This method has been proven in "RBT" field, which is currently producing oil at around 200 BOPD, 2.5 MMSCFD and also found by-passed gas potential in "PLB" sand, in addition to by-passed oil. This production will increase gradually later through the addition of more work over or well service jobs.

Introduction
"RBT" field is one of mature field that is operated by PT Medco E&P Indonesia. It is located in South Sumatera, Indonesia, and was discovered in October 1972. This field was originaly developed as oil field since 1974 and has produced from a multilayer reservoir named "PLB" sand, which has 6 (six) main productive layer zones and several other thin layers. The peak oil production was 1630 BOPD and then was declining to 300 BOPD in 9 years production time. In 1990 this field was converted into a gas field producer with small condensate and is still producing now.
As mature field reactivation and optimization is becoming an important aspect for increasing oil production at this time, effort to find bypassed oil in "RBT" Field was started in mid of 2011, started with initial field review, data rebuild and update, workover candidate selection and then followed by re-activation and workover campaign in 2012.

Field review, rebuild & update data
The initial effort to find by-passed oil potency in "RBT" Field were examining cumulative production allocation and analyzing historical production data from each zone and sand layer. These steps also became the main challenge as there were lack of detailed historical oil production and allocation especially in commingle zone.
Why is it Possible to Produce Oil from the Ekofisk Field for Another 40 Years?
Authors: Puntervold Tina , Strand Skule , Ellouz Raed , Austad Tor 
Published: May 2016

Abstract
The Ekofisk field, which is a naturally fractured chalk field, was the first offshore oilfield that was put on production in Norway in 1972. The field was produced by pressure depletion the first 10 years, and the initial recovery was estimated to only 17%. Due to the high porosity, up to 40%, significant compaction of the reservoir rock was observed. Injection of seawater was approved in 1983 and it was a great success. The expected oil recovery was adjusted to 46%. The Ekofisk formation is characterized as: low permeability in the matrix blocks (1–2 mD), high reservoir temperature (130 °C), low initial water saturation (5 -10%), and the rock appeared to be preferential oil-wet. Under such conditions, water-based EOR can only be successful if the fluid is able to change wetting properties of the rock in such a way as to increase the capillary forces. Intensive research during the last decade has proven that seawater at high temperatures acts as a "Smart Water" being able to improve the water wetness of carbonates. Even though the reservoir pressure was increased to the initial pressure, seawater had a weakening effect on the rock, and compaction is still taking place (about 10–12 cm/year) thus being a drive mechanism for oil recovery. The estimated oil recovery has now been increased to about 55%. Research show that seawater can even be modified to improve the oil recovery from the Ekofisk field, in a spontaneous imbibition process, by an additional 10% compared to ordinary seawater.
The fundamental knowledge of the effect of seawater on oil recovery from the Ekofisk formation has been important when the decision recently was made to invest in extending the oil production from the field for another 40 years.

Introduction
Ekofisk was the first oil field that was put on production in Norway in 1972. It is a naturally fractured chalk reservoir consisting of three formations:Tor formation - preferentially water-wet,Lower Ekofisk - neutral to low water wetness,Upper Ekofisk - neutral to preferentially oil-wet. Important reservoir parameters are: matrix permeability 0.1–10 mD, porosity 30–33%, reservoir temperature about 130 °C, initial water saturation about 15–20%. The reservoir has an oil column of more than 300 m and lies 2900–3250m below sea level.1 The field was initially developed for oil recovery by pressure depletion with an estimated oil recovery factor of 17%. After producing the reservoir below the bubble point, the operator and authorities in 1987 agreed upon a water injection program for three reasons: (1) Pressure support; (2) Oil displacement; (3) Decrease or prevent compaction of the reservoir rock. The following experience showed that the displacement of oil by seawater was a great success, and it actually appeared to be more effective than expected from laboratory experiments. The expected recovery factor for Ekofisk has gradually been adjusted to slightly above 50%.
A Novel Approach of H2S Corrosion Modeling in Oil/Gas Production Pipeline
Authors: R. Siagian Utjok W. , Siregar Hasian P. Septoratno , Santoso Ryan Kurniawan , Salam Damian Dion , Sumarli Shieren 
Published: May 2016

Abstract
Corrosion is a critical problem during Oil/Gas production, especially in sour field, Hydrogen Sulfide is the biggest contributor in the corrosion of production facilities. During the production period, pipeline will be corroded with reaction between H2S and Fe. This reaction will be occured differently in various temperature which determines the rate of your pipeline becoming thinner and thinner then will be unsafe. This paper presents a study about corrosion phenomena in production pipeline in sour field by analyzing the heat transfer to determine the corrosion rate in every part of the pipeline. An analytical model for heat transfer is coupled with fluid flow model, frictional heat and considering the Joule Thomsoneffect for steady-state condition. Then, from the analysis of the heat transfer, the corrosion rate in every section of the pipeline, 300 ft, will be obtained. This corrosion rate is determined from the analytical model. This model is applicable to be used in onshore and deepwater cases, depending on the surrounding condition. Thus, the position in which corrosion happened worst can be located. Coating or doing material selection for the several part of the pipeline could be a solution to prolong the age of the pipeline. Effectiveness is about how long the coating or the material selecting would be placed. Then, it could finally contribute in economical analysis about how much would be invested to reduce the impact of corrosion to assure the better production.

1. Introduction
It is a fact that corrosion is always happened during oil/gas production and there is nothing to do to eliminate it. The only way to do is to make the process occur more slowly. Corrosion will damage production facilities which are exposed by the fluid and surrounding environment containing corroding agents such as H2S, CO2, etc. In this paper, the main concern is H2S as the agent which can trigger the corrosion process happens. The existence of corrosion on the production facilities will disturb the flow assurance and make the production cost increase. Corrosion will make the pipe wall become thinner, then reduce the diameter of the pipe. Corrosion will also change the pipe roughness. Thus, these two occuring phenomena will significantly change the flow characteristic, then damage the flow assurance. In order to ensure the flow assurance, preventive actions such as pipe coating, injecting inhibitor, etc are always done. In the other hand, all of those actions also have to be considered from the economic view. Thus, a right action has to be chosen to ensure the flow assurance and also be economically done. In this paper, authors develop mathematical model to choose and predict the right action to be executed. Authors also suggest pipe coating and material selection as a right solution to answer the flow assurance problems in that condition.
Computation of Relative Permeability Curves in Middle Eastern Carbonates Using Digital Rock Physics
Authors: Dakshinamurthy Natarajan , Verma Naveen Kumar , Abdul Salam Tareq , Al-Sammak Ibrahim , Koronfol Safouh , Dernaika Moustafa , Teh W J 
Published: May 2016

Abstract
Digital Rock Physics (DRP) has significantly evolved in the last few years and added invaluable contributions in improving core characterization and in providing high quality advanced SCAL measurements, emphasized through various studies (Al Mansoori et al., 2014 and Kalam et al., 2011).
This paper represents a unique DRP relative permeability SCAL study done on two plug samples from a carbonate reservoir in the Middle East. It outlines the DRP method used to determine the relative permeability curves including sub-sample selection, high resolution CT scanning (down to nano level), generation of the 3D rock models, and simulation of fluid flow displacements.
The paper will also discuss the power of pore scale imaging and how it helps in understanding macro property variations. The DRP results are comparable to the SCAL results of same formation of nearby fields and are currently being used for the Full Field simulation. The conclusions will be supported by a comparison with physical lab measurements that were done independently on samples of the same formation from the same well's core.
Such comparison will demonstrate the added value in using DRP, and will show the effectiveness of the technology in generating advanced SCAL data in a significantly shorter timeframe compared to conventional laboratory measurements.

Introduction
Relative permeability (Kr) curves provide macroscopic description of the way in which two (or three) phases flow together locally in a porous medium (Honarpour et al., 1986 and 1995; Heaviside, 1991). Imbibition water-oil Kr data are critical in the evaluation and management of fields having natural water influx or having planned or actual water-flooding. However, high percentage of such laboratory measurements yields unrepresentative data that cannot be used in reservoir simulation models or as input for history matching of production profiles. In addition, the traditional laboratory evaluation methods may not be applicable to every testing condition or every type of reservoir rock and hence the continued development of laboratory methods is required to help characterize and understand challenging reservoir behaviors (Dernaika, 2010 and Serag et al., 2010).
Digital imaging technology has been extensively used in the petroleum industry to obtain fast and reliable core data from reservoir rock samples. The technology (Digital Rock Physics) has contributed reliably to reservoir core characterization through the application of Dual Energy X-ray CT Scanning (Walls and Armbruster, 2012 and Al-Owihan et al., 2014) and to the prediction of reservoir engineering quantities like capillary pressure and relative permeability through direct simulation into high resolution 3D images (Amabeoku et al., 2013, De Prisco et al., 2012, Mu et al., 2012 and Grader et al., 2010)
Subsea Emergency Response System (SERS): Optimised Response for Subsea Production Well Incidents in the Gulf of Guinea
Authors: Bourguignon Jean Claude , Ryan Michael , Bretenou Michel 
Published: May 2016

Abstract
As a major operator of subsea wells, the technological risks associated with the production phase of deepwater wells was a focus of efforts in the post-Macondo era. Shortly after this catastrophic incident, Total launched a number of in-house initiatives and in parallel joined several industry projects. Among its own, in-house initiatives, Total created the Subsea Emergency Response System Project (SERS), in order to develop and supply tools for use if an intervention was required in response to an uncontrolled hydrocarbon leak on a Total production subsea well. The SERS Project has now progressed significantly and is about to deliver its first set of tools to its operating affiliates in the Gulf of Guinea. This set of tools can be split into two systems:A Dynamic Killing System, capable of injecting fluids through the subsea Xmas tree choke interface,A Diverter System, which can be connected on top of each subsea Xmas tree for capping or diverting a leak.
The SERS Project is considered to be a significant advancement of the response capability for Totals affiliates. The design, fabrication and placement of a capping and diversion response in the Gulf of Guinea region, where Total has its greatest concentration of subsea wells, is a major improvement of Total's capability to intervene should a subsea problem arise. The new concept of a capping and diversion system adapted directly to the constraints of a blowout on a subsea production well is an industry first. The flexibility inherent in the design provides a solution that is adaptable to various types of well kill, horizontal or vertical Xmas trees, compatible with numerous installation workover control systems and is even adaptable to a well control incident on a drilling BOP.
This paper describes these two systems and the deployment strategy developed by Total to minimize the consequences of a subsea hydrocarbon leak during the production phase.

Introduction
Total is a major operator of deepwater subsea wells worldwide and particularly in the Gulf of Guinea region. Total operates around 250 subsea wells in 2014, a number which will rise to around 1000 in 10 years time with the arrival of numerous deepwater projects. In this respect, Total has an exposure to well control events not only linked to the drilling of these subsea wells, a period which lasts just a few weeks, but also to the production phase which clearly lasts for many years.