bluuebunny/crossref_metadata_2025_split huggingface dataset:
Enhancing CBM Exploitation with Crosswell Seismic: Case Histories
Authors: Dogra Sanjeev , morgan Thomas H. , Nalonnil Ajay , Shafiq Muhammad , Marion Bruce P. 
Published: May 2016

Abstract
Fundamental to successfully developing coal seam gas prospects is the ability to image fine scale structure and stratigraphy of coal seams and the surrounding formation away from the well so as to better estimate the next drilling location to target maximum net pay zones. Much has been written about seismic imaging in coal seam gas development over the past few years, yet conventional techniques of surface seismic and vertical seismic profiling have not met the resolution requirements to help in making more informed development decisions. Crosswell seismic is a proven technique that helps achieving a vertical resolution of 1–3 m, well within the range required for coal seam imaging. This paper discusses two case examples that highlight the imaging capability and potential applications of gas monitoring specific to coal reservoirs.

Introduction
Traditional well log data provide high-resolution measurements of the formation very close to the wellbore. Surface-based methods provide greater spatial coverage but coarser resolution. Crosswell seismic provides images of the interwell space at reservoir scale, hence bridging the measurement gap between the existing scales (Figure 1).
The first example (Case 1) is from the Powder River Basin covering areas of Wyoming and Montana, USA. The region supplies about 40 percent of coal in the United States. It is both a topographic drainage and geologic structural basin. The basin is so named because it is drained in part by the Powder River. The objective of the crosswell survey was to image coal seam structure and continuity. The survey will be both a tomographic velocity as well as a reflection image baseline in order to allow for future methane production and CO2 sequestration monitoring in the coal. One time lapse measurement comparing the velocity change with the baseline reflection image is discussed highlighting the effect of the onset of methane gas production.
The second example (Case 2) is from Burke County, North Dakota, USA and is in the central region of the Williston Basin. The geological subject was a 10 to 12 foot thick lignite coal complex consisting of two to four main units with interbedded sand stringers. The objective of the survey was to evaluate the coals for enhanced methane recovery and CO2 sequestration. In addition, a repeat survey was conducted for time lapse monitoring of CO2 injection. The injection results revealed that the multi-unit sequence of coal and sand effectively behaves as single fluid conduit.

Theory and Definitions
By using higher frequency sources that are deployed at the reservoir, crosswell seismic surveying generates high vertical resolution reflection images in the order of 1–3 m. This is due to the upper end of the frequency bandwidth of the transmitters used during acquisition which range from 800Hz to 2 kHz (depending on the imaging objective).
A Methodology of Underbalanced Drilling Design in Depleted Reservoir
Authors: Marbun Bonar Tua Halomoan , Zulkhifly Samuel , Hariz Irfan , Lumbangaol Calvin 
Published: May 2016

Abstract
When overbalanced drilling is done in depleted reservoir, lost circulation occurs and cause formation damaged. Underbalanced drilling (UBD) is proposed to be done to prevent lost circulation and increases production due to minimizes formation damaged. Besides, as formation being drilled underbalanced, it is possible to produce hydrocarbons from permeable zones, therefore earlier benefit could be acquired by company as producing phase began.
When a well is drilled underbalanced, formation fluids flow into the wellbore from any permeable formation in the open-hole section. It is possible to use the volumes of produced hydrocarbons, from a well drilled underbalanced, to provide an indication of the productivity of pay zones that have been penetrated (GRI, 1997).
The study in this paper is started from reservoir simulation to estimate the current reserve and plan for re-entry and new drilling well. Furthermore, drilling fluid selection and pressure window are analyzed based on reservoir characteristics and engineering approach. The last, the total hydrocarbons gained during underbalanced drilling in reservoir section will be predicted by Vogel equation.

Introduction
Drilling underbalanced into formations means to maintain a lower annular borehole pressure than the formation pore pressure while drilling a well (Nellayappan et al., 2008). The hydrostatic head of the drilling fluid is intentionally designed to be lower than the pressure of the formation being drilled. There are several benefits related to underbalanced drilling, which are:Underbalanced drilling can improve a penetration rate due to reduced "chip hold down" and decreases hydrostatic pressure at the bit face. Reduction in "chip hold down" refers to easier removal of solid cuttings, decreases hydrostatic pressure at the bit face, and reduces stress in the rock being drilled, thus allowing the formation to fail more easily. The bit life will be improved due to minimized contact with the formation while penetration depth is increased.In depleted reservoirs, lost circulation often occurs due to overbalanced drilling. With underbalanced drilling, there is no fluid flow into a formation, so lost circulation is reduced.With no flow into formation, formation damage is minimized, so productivity will increase, and the need for simulation lowered. Reduced formation skin will increase recoverable hydrocarbons so that the productivity will be superior to conventionally drilled wells. As there is no skin, the drainage area will increase and resulting in lower abandonment pressure; thus raising the recovery factor significantly more than overbalanced drilling would allow (Dahl and Vos, 1999).
Workflow For Surface Multiple Attenuation In Shallow Water
Authors: Hung Barry , Yang Kunlun 
Published: May 2016

Abstract
Surface related multiple elimination (SRME) method is known to have difficulties in attenuating shallow water multiples. Particularly, for water-layer related multiples in shallow water environment such as the Gulf of Thailand because the primary water-bottom reflection that is required by SRME for predicting the multiples is not recorded due to the near offset gap between the source and the streamers. Consequently, these multiples often obscure the interpretation of hydrocarbon reservoirs and significantly reduce the effectiveness of seismic inversion. Conventionally, predictive deconvolution in either x-t or tau-p domain is often used in processing workflow to suppress this kind of multiples. However, deconvolution also attenuates primary events that have a periodicity close to that of the water-layer. In this paper, we present a two-step processing workflow for removing free-surface multiples in shallow water situations. Firstly, we use a multi-channel prediction filter estimated from the multiples for attenuating short-period water-layer related multiples. Secondly, we apply SRME for suppressing other long-period surface multiples generated by sub-surfaces underneath the water-bottom.
Our workflow is applicable to any marine data that is plagued with surface multiples, particularly the short-period multiples caused shallow water-layer. It can also be used for reconstructing the water-bottom reflection that is not recorded in the data.
Through real-data examples from China and Australia, we demonstrate that our workflow provides an optimal multiple attenuation solution in shallow water environment in comparison with conventional methods such as t-p deconvolution or SRME alone.
This work adds to the understanding of multiple attenuation in shallow water by highlighting the shortcomings of the existing methods that are routinely used in seismic processing. Further, it presents how the issue can be tackled by separating the multiples into short-period and long-period ones so they can be handled by our proposed two-step workflow.
Application of Molecular Simulations to CO2-EOR: Phase-Equilibria and Interfacial Phenomena
Authors: Makimura Dai , Kunieda Makoto , Liang Yunfeng , Matsuoka Toshifumi , Takahashi Satoru , Okabe Hiroshi 
Published: May 2016

Abstract
Molecular simulation is a powerful technique by which we can obtain thermodynamic properties of the system of given composition at desired temperature and pressure, and it enables us to observe microscopic phenomena by direct visualization. In this work, two important phenomena related to CO2-EOR were investigated by molecular simulations: interfacial phenomena and phase-equilibria.
By molecular dynamics simulation, we have studied the effects of CO2 on oil-water interface properties. It was found that CO2 enriched in the interfacial region at all thermal conditions. While the oil-water interfacial tension (IFT) increases with pressure, the IFT could be reduced by CO2 about 1/3 at low pressure and half at higher pressure to a value ~ 25mN/m. Further analysis based on our MD trajectories show that the O=C=O is bonded to the water with "T-shaped structure", which provides the mechanism for the enrichment of CO2 at oil-water interface. The residual inneglectable IFT at high pressures implies that the connate or injected water existing in the reservoirs will strongly influence the transport of the CO2-oil solutes in a reservoir.
By using Gibbs Ensemble Monte Carlo simulation method, we computed phase equilibria of CO2 and petroleum fluids to obtain ternary phase diagrams. As an example, we have obtained vapor-liquid equilibria of a system consisting of CO2, nbutane and N2 and a system consisting of CO2, n-butane and n-decane. The calculation of hydrocarbon fluids with CO2 and N2 mixture will allow us to evaluate the effects of N2 impurity for CO2-EOR. And the calculation of CO2 and hydrocarbon mixtures will allow us to study the minimum miscible pressure (MMP). Such two systems were chosen in our study as the experimental data were available.
The application of GEMC techniques as well as MD simulations to a more realistic system including heavier hydrocarbons is straightforward.
B-Field Reservoir Characterization and Modeling - Carbonate Excess Permeability Using Single and Dual Porosity Models
Authors: Sun Michael 
Published: May 2016

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

Abstract
The B-field, located on Central Java, Indonesia, is a steep flanked carbonate structure of Oligo-Miocene age with approximately 1,000 m of relief relative to the surrounding platform. The extensive formation evaluation program for large carbonate oil fields shows that geologic features such as karst and fractures can be very effective to enhance productivity and thus production but they can also provide detrimental connection between the producing oil zone and the overlying gas and underlying water zones. Characterizing this type of system is a huge challenge for reservoir simulators.
This paper will discuss the results of a modeling study in characterizing the excess permeability, quantifying its impact on production, and representing its effect in simulation models. In this study, the karst features was modeled with an analogue-based dendritic pattern and the size and permeability of karst region was calibrated with production data. To model fracture excess permeability, a DFN (discrete fracture network) geologic model was built, upon which a DP (dual-porosity) simulation model was constructed. A series of DP sensitivity cases was designed and simulated to evaluate the range of production impact from fractures.
Although DP model is considered the most rigorous modeling technique available for fractures, the challenges are that it normally requires long simulation time and more importantly it needs significant amount of data for model verification and calibration. From the results of reservoir characterization and production comparison, it was demonstrated that a conventional single porosity model with modifications that mimic fracture connections is appropriate for the B-field. Two modifications adopted in this study were pseudo wells and permeability enhancement in the fracture-prone area. Pseudo wells, shutting in at surface but permitting cross-flow in designated reservoir intervals, were implemented to capture premature gas / water breakthrough phenomena that often observed in naturally fractured reservoirs. The permeability enhancement was intended to represent the positive impact of fractures on production by accelerating fluid movement through tighter reservoir. The results of DP model were used as a bench mark to determine the extent of permeability enhancement.
Geomechanical Evaluations Helped Successful Drilling Operation and Completion in Mature Fields with Depleted Reservoirs Interbedded with Weaker Formations
Authors: Khaksar Abbas , Rahman Khalil , White Adrian , Ghani Juanih , Asadi Mohammad S. , Stewart Keith 
Published: May 2016

Abstract
Hydrocarbon bearing reservoirs in the Southern Fields, Malay Basin, Malaysia contain in excess of 40 sandstone reservoirs interbedded with mudstones and coal seams. Years of production from shallower and mechanically weaker reservoirs resulted in pressure depletion whilst deeper and generally stronger reservoirs are still at early development stages and have normal pressures. High angle and horizontal development wells, to be completed without sand control, are planned for the deep reservoirs.
Reservoir pressure depletion results in a lower fracture gradient and a decrease in the drilling mud weight window. An improperly weighted mud may induce wellbore instability in weaker but normally pressured formations or mud losses while drilling heavily depleted shallow formations. Systematic geomechanical evaluations are required to assess the drillability of shallow depleted reservoirs and the feasibility of horizontal wells without sand control for deeper normally pressured reservoirs.
In a series of studies, a full-scale geomechanical model was developed, validated and updated using core, logs and drilling data from wells in the area. In particular, a total mud loss event in depleted formations in a recent well and rock mechanical data were used to establish the pore pressure-stress coupling (path) factor, an important parameter required for well control and managed pressure drilling operations. Subsequent drilling campaigns have all been successful via good drilling practices and using the recommended mud programs based on previous drilling experience and consistent with wellbore stability assessments. Some cementing issues were reported due to a much lower fracture gradient in the upper depleted sandstones sections but these issues have not prevented safe completion of the wells.
Sand production prediction studies were also carried out for a number of planned wells. Based on sanding assessments, well completion recommendations included cased and perforated completion, barefoot completion and openhole with predrilled liner completion depending on the well trajectory, rock fabrics, rock strengths and production conditions for individual cases. Production experiences to date have been consistent with the model prediction and completion recommendations (i.e. sandfree production from several wells with predrilled liner completion).
The Use of Risk-Based Inspection for Aging Pipelines in Sirikit Oilfield.
Authors: Areeniyom Paison 
Published: May 2016

Abstract
The Sirikit oilfield located in the north part of Thailand has now been in operation for 28 years and intends to continue production in excess of a further 10 years. The Sirikit oilfield manages 187 intra-field pipelines with total installed length of approximately 417 km. installed from 1983 onwards. A number of the infield pipelines have been in service for more than 20 years and with original design life of 15–20 years, they are reaching the end of or exceeding their original lives. Pipeline degradation due to corrosion leading to spills and production deferment has become critical problem. In addition, frequent and continuous inspection of pipelines to achieve sufficient and reliable inspection data with optimal inspection resource have become increasingly important.
In order to keep this oilfield long operational life as well as to assurance sustained pipelines safety and integrity, Sirikit oilfield has implemented the Risk Based Inspection (RBI) to assess a number of 187 infield pipelines with respect to corrosion mechanisms, inspection effectiveness, likelihood of failure and consequence to failure.
Pertaining to the results of the implementation, it was a successful implementation for Sirikit assets. The major success was identifying the risk, ensuring that the risk remains as low as reasonably practicable. Optimal inspection plan was also successfully established by extending a number of pipelines inspection intervals from 1 to 2–3 years under some certain conditions and will gradually increase to 4–5 years. The higher level of inspection and scrutiny to reduce potential threats on the pipelines based on what, where, when and how to inspect in order to control and reduce the risk to be within an acceptance level were used.
This paper describes the implementation of a risk-based inspection program for the Sirikit oilfield. The paper addresses the RBI matrix, the likelihood attributes, the consequence scores, and the overall risk. Pipelines are plotted on the RBI matrix to develop inspection priorities followed by inspection planning.
Using 3D Beam Q Migration For Imaging In The Presence Of Gas Accumulations In The Overburden
Authors: Xie Yi , Notfors Carl , Sun James , Xin Kefeng , Hung Barry , Zanussi Wayne , Soo Khok Ping 
Published: May 2016

Abstract
The presence of absorption anomalies in the overburden causes seismic images of the geological structures underneath to suffer from resolution degradation, wavelet distortion and amplitude dimming, therefore reduces our ability to image and interpret events inside the resulting "shadow zone". Imaging in the presence of gas accumulations in the overburden has long been recognized as a challenging problem, particularly in Southeast Asia where gas receives increasing exploration and development attention. Thus, there is a need to compensate for the attenuation due to shallow gas.
Conventionally, methods such as spectral decay analysis and inverse Q-filtering are used to address this issue. However, these methods fail to honor the geological properties of the earth's subsurface as they do not honor the actual wave propagation in the earth during which seismic energy is attenuated. A more accurate way to compensate for the absorption effects is to handle it during the process of migration which fully honors actual wave paths.
To address this issue, we have developed a 3D beam Q migration technique for imaging in the presence of absorption in the overburden. As an extension from conventional 3D acoustic beam migration technology for imaging in visco-acoustic medium, our 3D beam Q migration has the capability to naturally handle multi-pathing while keeping the advantages of Kirchhoff migration, such as efficiency, flexibility, and capability to produce offset gathers for velocity model building.
In this paper, we will describe our 3D beam Q migration technique and apply it together with our ray-based tomographic Q inversion technique for estimating absorption to a real data from east coast of Peninsular Malaysia which suffers from degraded seismic data quality due to multiple overlying gas accumulations. We will demonstrate how our 3D Q migration technique and Q tomographic inversion technique can be used for better imaging in the presence of gas accumulations in the overburden.

Introduction
In the early days of seismic imaging, the main goal of migration was to get structural information about the subsurface geology. Now imaging the true reflectivity of the subsurface has attracted wide attention in the seismic exploration industry. This requires correct treatment of the factors affecting the amplitude of waves during the extrapolation and imaging steps of migration. Amplitude preserving migration methods account for geometrical spreading (e.g., Zhang et al, 2002). However, the factor of intrinsic absorption, such as gas within shallow sediments, is commonly neglected in conventional migration methods.
Interpreting Electro-facies And Fractures For An Oligocene Sandstone Reservoir Using Borehole Images Acquired In Oil-base Mud With Full Core Calibration: A Case Study From Songkhla Basin, Thailand
Authors: Li Bingjian , Peace Geoff , The Ronald , MayKho Sirinya , Farag Sherif M. 
Published: May 2016

Abstract
The Oligocene reservoirs in the Songkhla Basin of Thailand are predominantly fluvial-deltaic deposits. There are several geological challenges describing these reservoirs. Firstly, it is sometimes difficult to determine lithology from conventional open-hole logs. Secondly, defining facies can be challenging due to the lack of sedimentary structure information from any of the conventional open-hole logs. Thirdly, natural fractures and sub-seismic faults exist in the formation which adds more complexity to the reservoirs. Geoscientists have traditionally incurred high operating costs to acquire conventional cores needed to resolve these challenges.
This paper presents an alternative technique for sedimentary characterization of the Oligocene sandstone reservoirs in the Songkhla Basin utilizing electrical image logs acquired in synthetic-based drilling fluids, along with Elemental Capture Spectroscopy (ECS) and Nuclear Magnetic Resonance (NMR) data. Lithology has been defined a lot more accurately using ECS data than by using conventional open-hole logs alone. Electro-facies have been successfully determined by integrating sedimentary structure and texture information interpreted from image and NMR logs with lithology information from ECS. In addition, the natural fractures have been interpreted from image logs. These interpretations of lithology, electro-facies and fractures have been calibrated with core data acquired in the same well. The output from this pilot study was a cost-effective solution for electro-facies and fracture analysis. It also provided input to constrain the sedimentological settings and reservoir modeling for the field.
Pore Scale Visualization and Simulation of Miscible Displacement Process under Gravity Domination
Authors: Mohiuddin Zeeshan , Haghighi Manouchehr , Stokes Yvonne , Carageorgos Themis , Gibbins Danny 
Published: May 2016

Abstract
This paper presents both visualization and flow simulation of glass micromodel experiments which are performed to visualize the gravity dominated miscible gas displacement process. This approach enables to simulate the exact porous pattern on which the micromodel experiments are performed.
At first, a porous pattern for experiments was constructed and then etched onto a glass plate. An experiment was performed at 45o dip angle at injection rate of 0.002 ml/min to visualize the displacement of two miscible fluids under gravity domination. Butanol and Iso-octane were selected as in situ and injected fluids respectively. The mobility and density ratio of these two fluids are comparable with medium API oil and CO2 at reservoir conditions. For simulation, the porous pattern was exported to the finite element analysis software, COMSOL Multiphysics, so that simulations of micromodel experiments were performed for the same porous pattern as used for experiments. To simulate miscible displacement, the Navier-Stokes and continuity equations were used to calculate pressure and velocity fields in the solute and solvent regions, while the convection-diffusion equation was used to calculate solute concentration in the mixture during the displacement.
The experimental visual results were processed and compared with the simulation results indicating a good match between experiments and simulation. The validated model can be used to simulate and to find the optimized conditions and controlling parameters at different conditions for the gravity assisted miscible displacement process.