bluuebunny/crossref_metadata_2025 huggingface dataset:
Integrated Reservoir Characterization And Development Through An Improved Workflow Approach To Couple A Three Dimensional Seismic Study Results And Reservoir Numerical Simulation: Revealing The Effect Of Structural Features In La Victoria Field
Authors: Castillo Karilys , Urdaneta Marisely , Askoul Yamal Eduardo
Published: May 2016

A detailed seismic interpretation for reservoir characterization is a powerful tool to obtain information in the inter-well area for the purposes of field management and development. This paper presents a workflow approach to characterize La Victoria Field reservoirs, which belongs to Apure State in the Southwest of Venezuela, particularly Escandalosa M Sand of Escandalosa Formation. The available 3D seismic data have been used to predict small-scale faults as well as presence of internal compartments where undrained zones or bypassed oil might be located in a mature oilfield. Additionally, reservoir engineering techniques as numerical simulation helped to verify reservoir parameters estimated by history matching in a black oil simulator, such as the sealing character of some faults, identified from seismic interpretation.

Introduction

La Victoria Oilfield is located in Apure State, Southwest of Venezuela, specifically at 60 km to the Southwest of Guasdualito Village and 6 Km to the West of Colombian - Venezuelan boundary, between Uribante - Apure Rivers (North) and Arauca River (South). This oilfield produces from Tertiary and Cretaceous reservoirs.

The Escandalosa M Sand is a cretaceous unit, which highly homogeneous; consequently, the structural characterization is the key in order to find drilling opportunities in this field. Seismic attributes reveal features and patterns; which can be useful to understand the geological structure and to build a robust 3D geomodel. Also, this reservoir represents a mature reservoir, in consequence is necessary to do a detailed geological and geophysical and reservoir engineering analysis to find undrained zones or bypassed oil to propose an optimal placement of a well.

The aim of this work is to present a methodology for creating an Integrated Structural Geological Model from seismic attributes and well logs in order to build a 3D geomodel that reproduces as exactly as possible the small geological features, and finally create the simulation model which allows identifying undrained zones. Although this work was made along of all oilfield, we will focus this article on the northern part of the field, because was there where the locations were proposed and drilled with excellent results, confirming the results of this study.
Hydrogen Imbalance in Petroleum Source
Authors: Bhattacharya Swapan Kumar
Published: May 2016

The average molar hydrogen concentration relative to carbon is always higher in petroleum than the source organic matter and thus it becomes a serious concern for the theory of organic origin. On the other hand, abiogenic theory of petroleum generation do not have this problem because hydrogen is available even deep inside the earth either due to serpentinization or by chemical reactions of freshly cut ferromagnesian mineral surface with water. Although available hydrogen thus favours abiogenic theory for petroleum generation, but the field and other laboratory evidences in favour of organic origin are so convincing that it is very difficult to accept generation of petroleum other than the organic source. In this work attempt has been made to critically review this hydrogen imbalance problem within a fence of organic origin of petroleum.

Though the organic matter is deficient in hydrogen, yet it can generate petroleum if its deficiency is compensated by some other source. Fischer-Tropsch (FT) synthesis, in which coal and organic biomass is catalytically converted to liquid petroleum using water gas as a source of hydrogen, experimentally supports the above statement. Many of the recent workers believe petroleum is generated from organic matter and the deficient hydrogen is made available from the subsurface water. This is further supported by hydrous pyrolysis and also by isotope exchange reactions with water.

In this paper critical review is made to understand the limitations of these supporting evidences. High pressure temperature conditions in FT synthesis cannot be a model for natural petroleum generation and thermodynamically it can be shown that it is nearly impossible to spontaneously convert dead organic matter to petroleum compounds. An alternate solution is proposed here suggesting petroleum is possibly generated using dominantly the lipids of organic matter that has higher H/C compared to petroleum.
Conversion of Olefins in LPG through hydrogenation
Authors: Gurumoorthi Gurulakshmanan , Vanjilingam Balaji , Digraskar Ganesh
Published: May 2016

The objective is to remove undesirable components namely olefins present in the Liquefied petroleum gas (LPG) stream in order to match the quality pertaining to environmental aspects and safety requirements which are achieved by processing the unsaturated hydrocarbons to the saturated hydrocarbon product. The principal reason for removing the olefins is that it certainly produces significant smoke based on the mole percent of olefin content when the fuel is burnt and that which is not desirable when it is being utilized by the end users inorder to provide a smoke free environment. Hence a detailed study and analysis which was carried out for hydrogenating the olefins to produce saturates have been discussed here. The complete analyses have been modelled and simulated using process modelling software hysys. The efficiency in terms of the final achievable product with respect to the throughput plays a vital role in the quality of saturated LPG product. The results are analyzed with respect to the feedstock composition of unsaturated LPG to the obtained saturated LPG product composition. This gas processing method of treating unsaturated LPG provides us a cleaner and safe environment by reducing the emission / smoke intensity levels while burning the fuel.

Description of the model

In order to mitigate the olefins in the LPG and achieve desired specification, it is intended to go for a Hydrogenation facility to saturate olefins. The feedstock comprises of known composition of the liquefied petroleum gas with identified mole percent of the unsaturated hydrocarbons. The complete model is carried out in the process modelling software, Hysys. Peng-robinson property package is used as the simulation basis.

Olefins in LPG entering into the feed vessel at a pressure of 26 bar and 40°C (Refer to Figure 1 for the schematic representation of the hydrogenation facility), is then pumped via feed pump to the equalizer. Fresh hydrogen stream is mixed at the equalizer for hydrogenation reaction to occur in the Hydrogenation reactor. Mixer upstream of the reactor ensures that proper mixing takes place for enhancing the reactivity of this two phase flow. The reaction is input for 98% conversion of the base components which are fed as input with appropriate stoichiometric coefficients. Hydrogenation reactor is loaded with specific metal based catalysts which have ability to convert olefins to saturated hydrocarbons. The exothermicity causes an increased temperature in the product. The flow in the reactor to be taken care to avoid channelling effects for more efficient conversion. There are two beds of reactor considered in the reactor. Each reaction continues until the specified conversion is attained or until a limiting reactant is depleted.
Multiples, Diffractions and Diffracted Multiples in the South China Sea: How Dense Does Our Acquisition Geometry Need to Be?
Authors: Quinn Rosemary , Comeaux Lynn
Published: May 2016

Multiples, diffractions and their multiples are a common feature of marine seismic data. In some areas of the South China Sea, the residual multiples are a significant problem as they are coincident with the reservoir section. In such cases, we need to devote additional resources to further attenuate the multiples, particularly the diffracted multiples. The challenge is to assess how much effort is sufficient and whether that effort is required during data acquisition, data processing, or both?

The work presented in this paper is the result of a real problem that we faced a couple of years ago when planning a seismic survey in the South China Sea. In the absence of 3D seismic data from nearby, the challenge was to demonstrate that 2D SRME would be inadequate in this area and that denser data acquisition would be required to attenuate multiples sufficiently to allow the 3D seismic data to be used for development drilling.

The requirement for 3D SRME in areas with rugose seabeds or other multiple generating interfaces is well-documented (van Borselen et al 2005, McHugo et al 2009 and Hung et al 2010 for example). That is one aspect of the challenge faced in the area of this case study: the seabed is locally steeply-dipping and there are shallow diffractors that generate structurally complicated multiples. Both of these factors indicate that 3D SRME would be more effective at attenuating multiples on data from this area than 2D SRME; this requirement was successfully argued using analogue data examples.

It is well understood that aliased multiples cannot be effectively attenuated during data processing. We used 2D lines where the seabed multiple was well-attenuated and only the diffracted multiples were troublesome to conduct a decimation test. Ambient noise was attenuated then traces were dropped without an anti-alias filter from 6.25m to give a trace spacing of 12.5m, 18.75m and 25m in the shot domain. This simulates the cross-line trace interval that would be achieved with 50m, 75m and 100m streamer spacing and dual source flip-flop acquisition geometry. Using this technique we were able to demonstrate that the minimum acceptable streamer spacing would be 75m, assuming that one pass of trace interpolation could be used prior to demultiple processing.

Introduction

The work presented in this paper is the result of a real problem that we were faced with a couple of years ago when planning a seismic survey in the South China Sea. The reservoir interval is contamined with residual multiples and diffracted multiples. The challenge we had was to demonstrate that not only was 3D SRME probably the solution to the problem, but also that we needed to acquire data more densely than had been done previously in the area. Both these options require significant additional expenditure, but the acquisition option is around 2 orders of magnitude more expensive than the processing option.
Malaysia East Belumut Field: Doubling a Marginal Field's Reserves by Understanding the Application of Enabling Technology
Authors: Ong Tee-suan , Lambert Mark , Goodin Barry John , Othman Mohamad
Published: May 2016

Successful application of enabling technologies in the phased development of Malaysia's marginal East Belumut field resulted in reserves doubling between Field Development approval in 2006 and post development in 2010. The field development has multiple challenges given the thin-oil column (46 feet) entirely within the transition zone, unfavorable crude quality, a large gas-cap and extensive bottom water, a large but low relief structure, and a shallow poorly consolidated sandstone reservoir.

Developing such a marginal field requires extensive reservoir simulation to plan the optimal well spacing, counts, lengths, vertical positioning of horizontal well or landing depths, and withdrawal rates. To implement the plan, drilling and geosteering technologies must achieve extended reach wells with long (greater than 6000 feet) open-hole horizontal sections. Completions require Stand Alone Screens (SAS) and Inflow Control Devices (ICD) to prevent sand production and to distribute the drawdown evenly along the entire well length. The ICD designs are modeled using segmented well simulation models with ICD configurations.

After the initial development, extensive field trials are conducted to measure well drawdown, water breakthrough timing, and water-cut increase. Production Logging Tools (PLT) coupled with tractor and tracer technologies are applied to confirm the entire horizontal section contributes to total fluid inflow. The field trial data is subsequently used for validating the simulation result and optimizing the next phase of development.

At the end of 2010 the field has two and a half years of production history from two successful phases of development (14 wells drilled). A third phase of development drilling has begun in second quarter 2011 and it is expected the final well count for the final development will be 30 to 40 horizontal producers. The oil production build-up and rate are performing better than those envisaged in the original development plan. As a result the reserves have doubled since the initial development.

Introduction

East Belumut field is located 160 miles northeast of Terengganu, Malaysia near Vietnam and Indonesia (Figure 1). East Belumut's primary oil reservoir is a Tertiary-aged, areally extensive, highly porous and permeable oil reservoir. East Belumut is considered a marginal field development due to the initial low reserves. East Belumut is a particularly challenging development due to the thin 46-feet oil column, the low-gravity (23°API) high-viscosity (3cP) oil, and the productive interval being entirely within the oil-water transition zone. Furthermore, the field has a large but low relief structure, a shallow poorly consolidated sandstone reservoir and the thin oil column is sandwiched between an underlying bottom aquifer and a gas cap.
FLNG Development: Strategic Approaches to New Growth Challenges
Authors: Bunnag Maneenapang , Amarutanon Nunthachai , Nitayaphan Saranee , Aimcharoenchaiyakul Manit
Published: May 2016

Underneath the ground, the world still left a quarter of its natural gas resources (approximately 2 billion TCF) undeveloped or "Stranded" in offshore. Many gas fields were discovered in many decades ago, but the resources of those fields could not commercially be justified for the development so they were classified as marginal fields. One of the most promising solutions known as "Floating Liquefied Natural Gas or FLNG" is lately growing and foreseen as potential technical to monetize these marginal gas fields offshore and near-shore. We are well aware of the potential in FLNG technology and consider it as the one of the most important initiatives to lead our organization to achieve target growth.

Many challenges in developing FLNG, however, have been found from major players in the past decade. Although land-based LNG and offshore FPSOs are each successfully proven in operations, combining the two technologies into FLNG is complicated and face various technical challenges e.g. safety, ship motion, topside processing, hull & containment, offloading, integration, and operation. The critical aspect of FLNG is space constraint, which requires fully attention in order to deliver inherently safe and fit-for-purpose installation. Altogether, FLNG concept shall fulfill a good balance between efficiency and simplicity to safeguard the reliability of the facility.

Moreover, commercial aspect of FLNG is also highly challenging. With costly investment, FLNG project shall be carefully ensured if it is economic viable in every step of the project. The sensitivity of market, LNG price, and demand & supply shall be reviewed and taken into consideration prior to making the Final Investment Decision (FID).

Certainly, FLNG initiative still has a lot of queries. However, after years of study and development in all aspects of floating liquefaction, it finally leads to the key conclusion that today there is no technical issue as "show stopper" for FLNG; whereas economic is also promisingly attractive. We believe that we have started on the right track and in the right sequence as well as adopting a risk management in selecting the right size and the right technology for FLNG.
Heterogeneity of the Hydrocarbon Distribution in Tertiary Sediments of North-East Sarawak
Authors: Ramli Mohd Syamim , Padmanabhan Eswaran
Published: May 2016

There are tremendous spatial and temporal variability within the sedimentary rock types of the Belait (Early-Mid Miocene) and Lambir (Mid-Miocene) Formations in North Eastern Sarawak. With the current renewed interest in oil and gas exploration in this part of Malaysia, evaluating the distributions of hydrocarbon resources in both Formations will be of valuable interests for the industry.

The IR spectra of both Formations showed presence of aliphatic and aromatic components. Total organic carbon results for both Formations show that majority of the samples from the Belait Formation possess much higher percentage of organic carbon contents than the Lambir Formation. In comparing the E4/E6 values, it is observed that the high E4/E6 values give rise to more aromatic components and low E4/E6 values show strong presence of aliphatic peaks in the spectra. Positive relationship exists between the mean pore size and E4/E6 in the Lambir Formation, whereas, in the Belait Formation, the same trend is observed between the porosity and E4/E6 ratios.

Variability in these geochemical patterns indicate that there are differences in the quality of hydrocarbon between the Formations. The study shows that the variation of aromatic and aliphatic bonds found in the samples suggests differences in terrestrial origin and marine origin and a complicated depositional pattern temporally and spatially. Variability in the kerogen type discussed above indicates differences in the quality of hydrocarbon between the Formations. Heterogeneity within the same samples here suggests that different rates of migration might occur within the reservoir quality rocks of the Lambir Formation. This indicates differences in show type between both Formations. This study reemphasizes the importance of FTIR in current emerging trends in hydrocarbon research.

Introduction

North-West Borneo has been producing oil and gas since the 1903 with first onshore well drilled around Miri area in 1910 (Liechti et. al., 1960). Common rock Formations in this area includes Belait Formation (Mid - Upper Miocene), Lambir Formation (Lower - Upper Miocene), Tukau Formation (Lower Oligocene) and the Mid-Miocene Miri Formation (Figure 1).

The Belait Formation which is found in the North Eastern Sarawak has been interpreted as coastal and coastal plain deposits from a range of sedimentary environments associated with a relatively large delta (Wilford, 1961) or as fluviatile (Hutchinson, 2005). Towards the coast the environment changes into fully marine, and accordingly the Belait Formation merges gradually into the more marine Lambir or Miri Formations or the uppermost part of the Setap Shale Formation (Liechti et. al., 1960). The Formation consists predominantly of sandstones and alternating shales with minor limestone and marl in some places (Haile, 1957; Liechti et. al., 1960; Hutchinson, 2005).
Evaluation Of The South Makassar Basin Using An Integrated Multi-Discipline Approach
Authors: Courel Romain , Begg Paul , Kim Michelle Eui Kyong , Kokoh Leo , Nasif Khifni
Published: May 2016

The deepwater South Makassar basin is located offshore South Sulawesi in water depths averaging 2000m and is an under-explored region that was only drilled at its periphery. Talisman operates the Sageri, South Sageri and Sadang PSCs located in the central part of the basin.

This basin belongs to the South-Eastern margin of the Sundaland geological province. Tertiary sediment deposition occurred due to a rifting period of Eocene age, during which crustal extension created a tilted basement blocks topography, filled with continental to shallow-water syn-rift clastic sediments composed of volcanics, sands, coals, and shales. Carbonate development followed as more marine conditions prevailed by mid Eocene time. Rifting terminated at the end of the Eocene and the water depth increased, resulting in the progressive drowning of most carbonate buildups.

Ultra-deepwater conditions were then rapidly established in the central part of the basin, where sedimentation never caught up with the high subsidence resulting in a thick, shaly Neogene overburden section.

Talisman conducted a regional study to support the exploration of the South Makassar basin. However there was no data to calibrate the thermal state of the central deepwater area, which remained unknown due to the different nature or thickness of its crust.

A seabed data acquisition campaign including heat flow measurements provided the necessary calibration. The heat flow was then mapped using the BSR (Bottom Simulating Reflector) horizon, showing lateral variations within a range of 50 to 75 mW/m2, overall higher than in the adjoining North Makassar basin (30 - 60 mW/m2).

Results of the basin model indicate a significant present-day gas generative window in the centre of the basin and less mature kitchens in the southern grabens toward the south Platform. The primary structural traps are in place and receiving early hydrocarbons since the Mid-Miocene, but the migration/trapping efficiency is unknown.

The South Makassar is one of the remaining high potential frontier areas to be explored within Indonesia. Talisman's methodology to apply a regional multi-disciplined analysis to this basin has led to an early qualified evaluation of its petroleum system. This has allowed for timely business decisions to be made and as a result Talisman is in a strategically good position for the exploration of this basin.
Quantification of Pore Structure in a Miocene Carbonate Build-up of Central Luconia, Sarawak and Its Relationship to Sonic Velocity
Authors: Bashah Nor Sara Izzati , Pierson Bernard J.
Published: May 2016

Carbonate rocks frequently exhibit velocity-porosity relationships less predictable than those found in siliciclastics because of complex and heterogeneous pore structures. Traditional pore-type classifications describe these pore structures but are inadequate for correlations to the rock's physical properties.

In this preliminary research, velocity measurements of 20 core plugs of a Miocene carbonate platform in Central Luconia, Sarawak were made under dry-saturated condition at variable confining pressures and at effective pressures of 20MPa. The cross plot of measured velocity and porosity shows scattering along the Wyllie's time average equation. The large scattering in most cases will result in large uncertainties in seismic inversion and calculations of porosity volumes.

Digital image analysis (DIA) of thin section images were used to derived quantitative pore geometric parameters. Four DIA parameters proved to best describe several aspects of the pore system: dominant size (DOMsize), perimeter over area (PoA), roundness (?) and aspect ratio (AR). Combination of porosity, microporosity and these four geometric parameters improves coefficient of determination (R2) velocity estimation from 0.9219 to 0.9974.

Introduction

The Central Luconia Province is a broad and stable continental shelf, characterized by extensive development of Late Miocene carbonates. About 56 carbonate build-ups are proven to contain commercial quantities of non-associated gas in carbonate reservoirs. The Central Luconia Province contains about 40% of the total non-associated gas reserves of Malaysia (Yamin and Abolins, 1999).

Carbonate rocks frequently exhibit velocity-porosity relationships less predictable than those found in siliciclastics because of complex and heterogeneous pore structures. Traditional pore-type classifications describe these pore structures but are inadequate for correlations to the rock's physical properties.

This research aimed at verifying the inadequacy of porosity prediction from sonic velocities in Miocene carbonate reservoirs of Central Luconia and at investigating the main causes for the deviations between measured and calculated porosity. A total of 20 core plugs of a Miocene carbonate platform from a well in one of the carbonate platform of Central Luconia, Sarawak, were used for this preliminary verification.
Investigating the Effect of Polymer Gels Swelling Phenomenon under Reservoir Conditions on Polymer Conformance Control Process
Authors: Tu Tho N. , Wisup Bae
Published: May 2016

High water cut and water influx into production wells has become a serious problem in producing oil. Polymer gels treatment has been applied widely for near well bore regions to reduce water production. In water shut - off process, effective permeability, permeability reduction after gels treatment plays an important role for evaluating the level of reducing water cut. However, under complex reservoir conditions including pH, salinity, high pressure, and temperature, the polymer gels behavior is significantly affected by those parameters, such as pH affects to the gel strength; the difference in salinity concentration between formation water and polymer solvent (water) causes swelling phenomenon by osmotic pressure. Moreover, due to the presenting of reservoir crude oil, the shrinking phenomenon of polymer gels is taken into account. The swelling and shrinking phenomenon affect extremely on blocking porous media.

Laboratory experiments are carried out to perform these behaviors in batch system which is able to work at reservoir conditions. Two types of polymer with high and low molecular weight are used; chromium acetate is used as cross-linker agents. Several gels samples are tested in ambient and reservoir conditions (high pressure, high temperature, difference in salinity and pH) to investigate polymer gels behavior. These polymer gels samples are used in injecting into the sand-pack cores. Disproportional permeability reductions are measured with each polymer type.

Experiment results showed that the percent of increment in volume reaches 25 % (within 72 hours) with high salinity of polymer solvent (3%) and low salinity of formation water (0.5%). The lowest increment occurs when differential salinity is 0 % and 0.5 %. Moreover, water permeability is reduced strongly (67% of reduction) while it has less effect to oil permeability (17.5% of reduction) after polymer gels treatment. These investigations are important in evaluating the effectiveness of water shut-off process.
Enhancing CBM Exploitation with Crosswell Seismic: Case Histories
Authors: Dogra Sanjeev , morgan Thomas H. , Nalonnil Ajay , Shafiq Muhammad , Marion Bruce P.
Published: May 2016

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

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

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

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.

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

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

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

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

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.