bluuebunny/crossref_metadata_2025_split huggingface dataset:
CRS Seismic Processing: A New Approach To Obtain High-Resolution Images From Sparse 3D-Exploration Surveys
Authors: Coman Radu , Gierse Guido , Trappe Henning , Robinson Simon , Owens Michael , Moller Nielsen Esben 
Published: February 2016

Abstract
The CRS method assumes subsurface reflector elements with dip and curvature. The corresponding CRS stacking operator is not limited to a single CMP gather, but collects the reflection energy of a subsurface element from all contributing traces, including neighbour CMPs of the imaging location. CRS imaging of the sparse 3D data provided a strong increase in subsurface resolution, and signal-to-noise ratio. It also resolve the faulting which was largely buried in noise in conventional images. The combination of sparse 3D aquisition with CRS processing prove to be a suitable strategy for achieving good subsurface resolution at limited costs.

Introduction
Seismic acquisition in frontier areas faces a high risk when dealing with remote areas with difficult access, limited operation times due to seasonal influences and governmental restrictions, and a large uncertainty in the design of optimum acquisition parameters. Under such circumstances, high-fold 3D seismic surveying is not feasable, but 2D surveying may also not be appropriate to describe the areal extent of potential targets.
Sparse 3D surveys are frequently used as a compromise. A land data example from North Africa is presented here where large bin sizes (50x50m), and low data fold kept the acquisition turnaround in an acceptable time range. Seismic investigations focussed on flat target horizons, and low-throw faulting in the target regions. As expected, the results of standard time processing could not compete with results from nearby high-fold surveys. A much lower signal-to-noise ratio provided a very restricted resolution of the subsurface.
In an attempt to increase resolution, a CRS time processing was applied to these data. The CRS, or Common Reflection Surface method, is well suited to tackle noise problems in low-fold data, since it uses a much higher stacking fold than conventional time domain imaging. CRS obtains this high fold by assuming subsurface reflector elements with dip and curvature. In addition to the desired increase of signal-to-noise ratio and reflector continuity, the CRS processing aimed at resolving the faulting which was almost completely buried in noise in conventional images.

CRS Method
In time domain seismic imaging, the NMO/DMO stacking technique has been dominant for many decades. However, the simple subsurface model of the NMO stack, the loss in resolution by the DMO process, and the dependence on a user-derived velocity model has motivated the search for alternative time domain imaging methods.
Assessing Horizontal Stress Direction Using Seismic and Borehole Geometry Data: Study from Balam South Field
Authors: Umam Syafiul 
Published: February 2016

Abstract
This study demonstrated the utilization of seismic data and borehole geometry to determine the horizontal stress direction in Telisa Formation, Balam South Field Central Sumatra Basin, Indonesia. Telisa Formation is one of the oil reservoirs in the Balam South Field, where enhanced oil recovery project has been initiated in this shally-sand reservoir. In the reservoir of interest, seismic attributes gave strong indication of the presence of natural fractures. Acoustic impedance data showed relatively lower magnitude in the suspected natural fractures zone. The decrease of the acoustic impedance magnitude was interpreted as corresponding to the decrease of the acoustic seismic velocity in the suspected fractured zone.
Analysis of borehole shape from multi-arm caliper data in this field also supported the interpretation. The borehole shape is slightly elongated perpendicular to the interpreted maximum stress direction, giving indication of the presence of excess horizontal stress applied to the borehole from the maximum horizontal stress direction. Several other multi-arm caliper data were then acquired to confirm and calibrate the stress map for better interpretation result.
This study inferred the natural fractures orientation from seismic attributes to represent maximum horizontal stress direction. The interpreted map from the seismic data was then calibrated with the maximum horizontal stress orientation determined from the reconstructed borehole geometry. The final interpreted map of maximum horizontal stress direction was then used as a guideline for optimum hydraulic fracturing in the wells drilled in the waterflood project.

Introduction
Balam South Field is located in Central Sumatra, Indonesia (Fig. 1). Telisa Formation in Balam South Field is one of the major oil reservoirs in this field with the original oil in place is in the order of 650 MMBO. Telisa Formation is characterized by sand-shale laminations over approximately 100 feet (33 meter) thick interval in Balam South (Fig. 2). The trapping mechanism of this reservoir is anticlines controlled by northwest and North-South faults as shown in (Fig. 3).
Gas Field Integrated Modeling: A Practical Example of How To Optimize Production in a Mature Asset
Authors: El-Khawas K.M. , El-Ashry M. 
Published: February 2016

This reference is for an abstract only. A full paper was not submitted for this conference.

Abstract
This paper discusses the value of integrating subsurface and surface elements for gas fields located in Egypt's Western Desert concession. The Hydrocarbon accumulations in the operating company consist of oil and gasfields; first gas was discovered in 1982. Currently gas is produced from three fields that share the same plant and facilities. Each field is producing from two to five reservoirs with different productivity, pressure, Temperature, and PVT.
To optimize production and thereby maximize the remaining value of the asset, the use of an integrated forecast tool is beneficial. As the gas fields become a more mature asset, the allocation of well production to different production trains (High, medium, low pressure) in the future needs to be evaluated. Also the benefit of further optimisation on surface facility (e.g., decreasing the inlet pressure) in the tail-end production period could be addressed.
The integrated model was built with the aim to address the coupling of several reservoirs with the surface network to allow predicting the interactions between different fields/reservoir/pressure regimes, wells and facilities. The following key issues were addressed:–Pressure interaction between surface and subsurface–Pressure interference between different reservoirs and wells connected to a shared surface facility.–Influence of facility constraints, e.g., separator limits, commingled flowlines, etc. on a set of reservoirs connected to a shared facility.–Production optimization in the overall system against a set of common criteria or the current constrains.
The model's results allowed the operating company to improve its understanding of the interaction between the subsurface and surface activity and constraints. It serves as a tool to optimize the production of remaining reserves within a common timeframe.
State-of-the-Art of Heavy-Oil Development in China and Its Technology Challenges
Authors: Haiyan Hu , Shuhong Wu , Yitang Zhang , Dingmin Wei , zhong Guan 
Published: February 2016

Abstract
The commercial heavy oil development in China was initial in 1982 when the first cyclic steam stimulation (also known as steam huff and puff) pilot well test was successful in Liaohe Oil Field, northeast of China. In 1993, the annual heavy oil production had reached 70 million barrels and kept the level for more than 10 years.
The major development manner of heavy oil reservoir is steam injection, including cyclic steam (CSS) and steam flooding. CSS annual production is beyond 5.5 million barrels, more than 80% of heavy oil production. Steam flooding, successful in developing shallow heavy oil reservoir such as Kalamy oil reservoir, northwest of China, accounts for 8% heavy oil production with the highest annual production nearly 7 million barrels. For more than 20 years development, great progress has been made in several technologies as followed. (1) Integrated steam huff and puff technology with recovery factor higher than 20% of OOIP (2) Steam flooding technology, including high-temperature profile conformance technology, survey technology and steam measurement technology. The recovery factor of shallow heavy oil reservoir is beyond 40% of OOIP. (3) Super-heavy oil development technology, including integrated heat technology, high-efficiency steam injection technology, playing an important role in maintaining heavy oil production level with the highest annual oil production beyond 16 million barrels.
Although lots of progresses have been made, several problems as followed exist in heavy oil reservoir development. (1) CSS enters into later stage, with low pressure, low oil production and so, poor recovery results. (2) No mature development manner following CSS has come into being. (3) Steam flooding in deep heavy oil reservoirs is still in pilot test. It will take a long time to make it commercial application. (4) Steam Assisted Gravity Drainage (SAGD), is also in pilot test being carried out in Liaohe oil field.
Evaluating Gas-Injection Performance in Fractured Reservoirs Using Discrete Fracture Network Models
Authors: Sahni A. , Bakenov R. , Kaveh D. , Narr W. , Dull D. 
Published: February 2016

This reference is for an abstract only. A full paper was not submitted for this conference.

Abstract
This paper presents an alternative approach to modeling gas injection performance in naturally fractured reservoirs. The two conventional methods of modeling fractures have been to either use a single porosity medium with enhanced tensor permeability or a dual porosity system, where the matrix feeds the higher permeability fracture network. The former approach captures variability in well productivity, which is important during primary production but may not be suitable for modeling displacement mechanisms at the large simulation grid block scale. The dual porosity approach may provide some more flexibility in accounting for displacement mechanisms (imbibition, drainage, gravity effects etc.), however, calibrating dual porosity models (using an appropriate matrix to fracture transfer coefficient) may again be difficult.
We discuss an alternative methodology for generating, simulating and evaluating displacement performance using Discrete Fracture Network (DFN)models. While computationally expensive, the DFN models for smaller sectors could be used to calibrate displacement performance of full field dual or single porosity models. We generated stochastic realizations of fracture patterns conditioned to available data on fracture spacing and orientation using a multi-point statistics approach. These stochastic realizations were used to investigate the impact of fracture characteristics on displacement behavior. Fractures were explicitly treated as discrete entities having extremely low pore volume and high transmissibility. The rock-fabric permeability realizations were generated using sequential gaussian simulation, honoring well log data.
The models used to demonstrate the DFN approach were 1500m X 1500mspatially, with thickness varying from 200– 400m. They comprised of one up-dip gas injector and two down-dip producers. Simulations with the DFN approach show the injected gas moving rapidly through the fracture network, with significant bypassing of oil. The effective permeability and dual porosity models on the other hand, displayed more stable gravity drainage behavior. Displacement characteristics observed from the DFN sector models were then used to calibratefull field dual porosity models. Simulations showed that with higher rockfabric permeability, the displacement efficiency was significantly improved. Sensitivity studies were conducted to investigate the impact of fracture spacing, rock fabric permeability and well intervention techniques on recovery using the DFN approach.
The Supergiant Kashagan Field: Making a Sweet Development Out of Sour Crude
Authors: Malik Z. , Charfeddine M. , Moore S. , Francia L. , Denby P. 
Published: February 2016

Introduction
The super Giant Kashagan field is located in a shallow-water (ice-locked during the winter), environmentally sensitive area of the Kazakh sector of the North Caspian Sea. The Kashagan field was discovered in 2000 by a consortium of oil companies. The current North Caspian PSA companies are affiliates of: ENI, ExxonMobil, Shell and TOTAL, each with 18.52% share, Conoco-Phillips (9.26%), Inpex and KazMunaiGaz (8.33%, each). Agip KCO (an ENI company) operates the field.
The Kashagan field is a deep, over pressured (initial reservoir pressure: 783 bar), isolated, carbonate build-up with a high-permeability, karstified and fractured rim and relatively low- permeability, stratified, platform interior. The field contains a 43-degree API light oil, with 15% H2S and 5% CO2, and contains more than 100 Tcf of associated gas.
One of the biggest challenges of the Kashagan field development is the management of huge volumes of highly sour associated gas. The consortium had essentially two options to address this challenge:A commercially unattractive, but technically not challenging, conventional choice of evacuating the sour gas to shore for treatment (H2S and CO2 removal) and sales; orA technically very challenging, but potentially economically beneficial, alternative of injecting the raw sour gas back into the reservoir.
This injection alternative, with its high discharge pressures and sour service, would extend the current capabilities of existing gas compression technologies. Nonetheless, it had the potential to significantly enhance oil recovery, as the Kashagan oil and injected gas are first contact miscible at pressures well below the initial reservoir pressure.
Before proceeding with such a decision (after all, miscible gas injection is usually a secondary, or even a tertiary, recovery technique), the consortium had to undertake extensive evaluations to ascertain the likelihood of subsurface and surface risks.
The paper describes the integrated approaches and the different technologies brought to bear to evaluate the likelihood of potential risks (such as breaching of cap rock integrity, early gas breakthrough or asphaltene precipitation), and to implement mitigating solutions. It presents the reservoir and gas management strategies to mitigate the risks of cap rock failure and premature gas breakthrough. It also mentions some of the technologies advocated to, notably, detect potential fracture growth, monitor gas front movement and shut-off high gas-oil ratio producing zones, efficiently and cost-effectively.
CO2 IOR Potential in Naturally Fractured Haft Kel Field, Iran
Authors: Alavian Sayyed Ahmad , Whitson Curtis Hays 
Published: February 2016

Abstract
We present results studying the IOR potential for CO2 injection in the naturally-fractured Haft Kel field, Iran, based on detailed compositional simulations of the matrix-fracture system. Oil recoveries from CO2 injection consistently range from 80–90% for reservoir pressures 1400 psia and higher (i.e. at and above current reservoir pressure of 1500–1800 psia). This compares with 15–25% recoveries reported for gas cap expansion and/or injection of hydrocarbon gas.
Fundamentally-different recovery mechanisms develop above and below 2000 psia, the pressure where CO2 density equals the reservoir oil density. At lower pressures, CO2 is less dense than reservoir oil and traditional gas-oil gravity segregation results, with a highly efficient process driven by gravity, compositional effects and IFT gradients that cause capillary-induced oil flow. At pressures greater than 2000 psia, CO2 density is greater than reservoir oil density, resulting in an unusual gravity drainage mechanism whereby CO2 enters the bottom of a matrix block and pushes oil out the sides and top of the matrix block.
The effect of several key parameters has been studied in detail – matrix permeability, matrix block size, matrix-matrix capillary continuity (stacked blocks), and the use of mixtures of CO2 and hydrocarbon gas. One of the key results is how the rate of recovery differs for HC and CO2 injection, and how it varies for CO2 injection for different model parameters.
IOR results are affected by grid sensitivity. Grid effects have been quantified and compared for different model parameters. Final IOR assessment is made using models where sufficient grid refinement is used to minimize grid sensitivity.
CO2 injection in fractured reservoirs in the Middle East appears to have great potential, even at relatively low pressures. Large sources of CO2 would need to be available from gas-driven power plants and reservoirs producing CO2 in significant quantities.

Introduction
When an oil-saturated matrix block is surrounded by gas in the fracture, oil will drain from the matrix as a result of density difference between the gas and the oil. However, drainage can occur only if the matrix block height is greater than the capillary entry height.
New Vision of the Shuaiba at a Regional Scale
Authors: Al-Mehsin K. , Pierson B. , Drysdale D. , Warrlich G. , Eberli G.P. , Droste H. 
Published: February 2016

This reference is for an abstract only. A full paper was not submitted for this conference.

Abstract
The regional integration of well data, seismic observations and published information from the southern part of the Arabian Peninsula has led to a breakthrough in understanding the stratigraphy and depositional history of the Shuaiba and in extracting implications regarding hydrocarbon prospectivity.
The Shuaiba Formation is composed of system tracts from two supersequences, and the following subdivision is proposed: The Lower Shuaiba contains a TST and HST of a supersequence (Early Aptian, earliest late Aptian), while the Upper Shuaiba is a LST prograding package of the next supersequence (late Aptian).The TST of the older supersequence is distributed more or less equally over the entire Shuaiba province and the HST of the same supersequence is characterized by the development of the Bab Basin with a well-marked differentiation between basin and margins. An unconformity separates this supersequence from the LST of the next Supersequence during which new carbonate facies prograded into the BabBasin. On the basis of this subdivision, we propose a new, unified stratigraphic nomenclature for the Shuaiba.
Depositional facies associated with the 3 supersequence systems tracts are markedly different. Monotonous, widespread carbonate facies dominated the older supersequence. During the HST, organic-rich fine carbonates accumulated in the Bab Basin while rudist-rich facies lined and vertically enhanced the southern and western basin margin or developed as relatively large isolated platforms on the eastern slope of the Bab Basin. In the LST of the younger supersequence, new platforms prograded into the Bab Basin in a series of sub-linear, regular clinoforms that grew either parallel to the pre-existing southern and western margins of the Bab Basin or in a series of concentric rings, away from pre-existing isolated platforms.
Extracting the detailed sequence stratigraphy of the clinoforms and understanding reservoir quality, presence of intraformational seals and trap configuration has allowed us to identify and predict areas of higher HC prospectivity in the southern part of the Arabian Peninsula.
Accurate Corrosion Prediction Through an Integrated Approach
Authors: Reddy Ramani V. , Nelson Jocelyn L. , Pacheco Jorge Luis , Kroen Charles F. 
Published: February 2016

Abstract
The ability to optimize the use of carbon steel in corrosive service presents many economic advantages, including minimizing the use of expensive corrosion resistant alloys, reducing well count by enabling optimized large bore completions, and eliminating additional offshore pipelines and facilities. An integrated approach to corrosion modeling and testing is employed by ExxonMobil to reliably extend the application of carbon steel.
The integrated approach to predicting corrosion has five primary elements:Rigorously establish the environmental conditions by conducting thermodynamic and compositional hydraulic analyses, and characterize how these conditions are expected to change over time.Identify the local environmental conditions and the types of corrosion that are expected to occur (e.g., weight loss, pitting, environmental cracking), including sensitivity and upset cases.Conduct realistic corrosion tests under the identified field conditions by simulating brine chemistry, dissolved acid gas concentrations, hydrocarbon effects, fluid shear stresses, and flow regime in appropriate laboratory equipment. Specialized laboratory test apparati, such as a large-diameter sour, multiphase flow loop and large-volume high-pressure high temperature autoclave test cells, have been designed and constructed to ensure proper reproduction of field conditions.Mathematically extrapolate the results of the laboratory tests to the field, enabling calculation of expected tubular life.Conduct life cycle cost analysis.
This paper will describe how this integrated approach to predicting corrosion is used to evaluate the use of carbon steel in oil and gas production environments. Special emphasis will be placed on the prediction of pitting corrosion in H2S-containing environments.

Introduction
From the material selection perspective, the design decision is generally between CRAs and carbon steel, often with inhibition. The ability to optimize the use of carbon steel in corrosive service often presents economic advantages, primarily through a significant reduction in capital expenditures. The ability to run wet gas and full wellstream pipelines and flowlines can further reduce costs by eliminating offshore dehydration facilities.
Main Cryogenic Heat Exchanger Replacement at Brunei LNG
Authors: Omarali Adimasyaton , Groeneweg Peter , Kaart Sander , Pek Barend Johan Jan 
Published: February 2016

Introduction
This paper addresses the economical and technical justification for the rejuvenation of the existing, 33 years old, Brunei LNG plant to extend its lifetime with a third 20-year contract period to 2033. After an introduction into the history of the development of the Brunei LNG plant, and its growth aspirations for the 21st century, the paper will further focus on the current Asset Reference Plan (ARP) and in particular the technical challenges of the replacement of the Main Cryogenic heat exchangers in four out of the five Brunei LNG production trains.

Brunei LNG History
The construction of Brunei LNG started in 1968, and first LNG was exported to Japan in 1972. The shareholders of the BLNG plant are the Brunei Government (50%), Mitsubishi Corporation (25%) and Shell (25%). Shell Global Solutions, has also been the technical advisor of the Brunei LNG plant since the initial phases of the project.
The BLNG project was the first to use the Propane Mixed refrigerant (C3/MR) process, with spool wound main cryogenic heat exchangers. In the original plant, eleven boilers generated the steam for the turbine driven refrigerant compressors. Treated river water is used as cooling medium in an open cooling cycle. Each liquefaction train has a separate gas treating section that consists of an acid gas removal unit, dehydration unit and mercury removal unit.
Originally, the BLNG project included four trains with a design capacity of 1.05 MTPA. During construction, the scope was increased with a fifth train of the same capacity. This fifth train started production in 1974. As the main cryogenic heat exchanger of the fifth train was produced later than the original four, an updated design was installed in train 5.

First Rejuvenation
Between 1992 and 1994, the first rejuvenation and debottlenecking project was carried out at BLNG. In subsequent years plant debottlenecking projects have been implemented and the production capacity reached a maximum of 7.3 MTPA or almost 140% of initial design capacity by 2003 (Fig. 1).