bluuebunny/crossref_metadata_2025 huggingface dataset:
Prospecting and Modelling the Deepwater Turbidite Through Integrated G&G Studies
Authors: Liau Min Hoe , Waters Kester , Johnson Howard David , Jackson Christopher A.L.
Published: May 2016

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

The study was focused on the Sheryl field located in Block 21/23a, Central North Sea, UK. This field was discovered in the Eocene Tay deepwater turbidite reservoir. A robust conceptual geological model was constructed via an integrated approach of utilising the rock physics forward modelling, seismic attribute and geological data for the purpose of further prospect evaluation and static model building.

Rock physics forward modelling was conducted prior to seismic data interpretation to build a geophysical database comprising the analogues of seismic responses under different rock properties and pore fluid contents. This database was used to enhance the accuracy in seismic data interpretation. The forward modelling results concluded that the MuRho (µ") and LambdaRho (???) parameters could be used as a lithology and fluid type indicators respectively. The AVO modelling showed that brine, oil and gas saturated sands are characterised by Class I, Class II to IIp and Class III AVO responses respectively.

The MuRho (µ") data was used along with the seismic reflectivity data to minimize the uncertainty in mapping the top and base of the reservoir, which will enhance the accuracy of the horizon based attribute calculations. In addition, the MuRho (µ") data was used as a tool to indicate the sand distribution in 3D space, in order to constraint the shale volume (Vsh) and porosity population within the static model.

Technical Contributions:

1) Demonstrate the use of integrated G&G approach in seismic attribute interpretation and prospect evaluation.

2) Making use of the G&G understandings in a mature field to minimise the risk in exploring the subtle stratigraphic traps.
Natural Gas Transportation Infrastructure Concepts
Authors: Amani Mahmood , Mohan Megha
Published: May 2016

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

Natural gas is rapidly gaining ground with its reputation as an alternative environmentally friendly fuel source. Currently major gas exporting countries are already exporting to major markets in Asia and Europe. Natural gas can be transported in a gaseous, liquid or solid phase; however, the infrastructure needed to transport gas via pipelines or in its liquid form as LNG is expensive.

For smaller countries which do not have sustainable field sources of their own, LNG may not be an economically feasible option. However, these countries are still prepared to invest in gas if an appropriate delivery and reception method can be developed.

This paper will explore the different means in which gas can be transported and attempts to determine the best economic form of delivery to nations without the necessary infrastructure. It will compare six different methods of transport of natural gas: LNG, PNG, CNG, GTS, GTL and GTW via the storage capacity, economical distance and simple payback period to find the most feasible method in terms of transporting to consuming nations.
Integrated Reservoir Modeling to Enable Development of a Complex Turbidite Deepwater Discovery
Authors: Yeo Jonathan Yeok Swee , Stone Greg
Published: May 2016

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

This paper presents a case study of the approach and methods applied in static and dynamic modeling of a complex deepwater turbidite oil discovery (Field A) located off the coast of Borneo. Field A was discovered in 2004 in water depths of 1500 to 2000 ft. Field A is operated by Shell with co-venturers ConocoPhillips (CoP) and PETRONAS Carigali Sdn Bhd (PCSB).

The field currently has 4 well penetrations from which an extensive array of static and dynamic data was collected. This paper aims to showcase the application of specialized static and dynamic modeling methods required to simulate the behavior of turbidite reservoirs. The paper will discuss the evolution of fit for purpose models produced at different stages of the project (from post-discovery to concept select) incorporating multiple sources of appraisal data (including interference and production tests).

The paper will highlight the value and impact of using detailed reservoir models to quantify subsurface uncertainties through creation of multiple subsurface realizations and application of experimental design. The use of these models as key tools for planning and executing Field A's appraisal program and subsequent development planning in order to constrain the uncertainty range and reduce risk in this challenging development setting, will also be discussed.
SVS Fracture Solutions: Complex Fractured Reservoir Modelling
Authors: Bazalgette Loic , Beintema Kike , Yassir Najwa al , Swaby Peter , Richard Pascal D. , Rawnsley Keith
Published: May 2016

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

The optimization of hydrocarbon production from complex naturally fractured reservoirs depends strongly on the accuracy of static models and on the upscaling processes applied to their properties to build dynamic simulation models. SVS Fracture Solutions is the Shell proprietary software that allows the co-visualisation and interrogation of static and dynamic fracture data sources, ranging from seismic to outcrop to wellbore/core scale. SVS Fracture Solutions applies geological and geomechanical principles to constrain the structural style and its control on natural fracture distributions in the subsurface. The rules acquired from the data and the structural/mechanical constraints are combined to forward model discrete fracture networks covering the range of uncertainties in the subsurface. New SVS functionalities are dedicated to in-depth structural analysis. One is presented which assesses the fault damage zone and its relationship to fracturing. Another functionality builds geomechanical constraints from various data sources such as well logs and seismic, to define mechanical units and their boundaries. This paper presents some applications of these new functionalities. The work is ultimately aimed at assigning dynamic properties to the discrete fracture network for dynamic simulation and the dynamic workflows are briefly described.
Gas Transport as Hydrate
Authors: Pallipurath Mohamed Iqbal
Published: May 2016

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

A new process of transportation of Natural Gas using Gas Hydrate is presented as applicable to land transport in India. India's vast resources of stranded gas fields can be economically brought to the consumer via this technology. Current methodologies are discussed and an appropriate form is presented in the context of domestic road and rail networks. Formation, storage, transport and recovery issues are addressed. Economic viability is investigated. Formation and Transport are redesigned to suit domestic conditions of labor and road/rail system.
Smart Completion Installation and Experience in a High Pressure Gas Environment in Champion West field, Offshore Brunei
Authors: Turco Agostino , Salakhetdinov Ravil , Dale-Pine Brigitte , Van Lelden Robert
Published: May 2016

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

The current phase of the Champion West Field Development is one of BSP's most challenging project to date for drilling and completion reasons. The Champion West field was discovered in 1975, but its rich oil and gas reserves lay dormant for 30 years, locked beneath the seabed in a complex web of reservoirs deemed too expensive to develop using conventional development plans. It is a large undeveloped oil and gas resource in Brunei. Hydrocarbons are found in shallow marine reservoirs - these vertically stacked, structurally dipping reservoirs are complex and contain various fluid fills ranging from gas only to gas with oil rims to oil. The project consists developing oil rim reservoirs using the novel snake well design and developing of significant gas resources using highly deviated and high-pressured gas wells. Four wells have been drilled to date utilizing advanced drilling technologies and smart-completion equipment to complete over many stacked reservoirs with different pressure regimes, whilst aiming to maximizing ultimate recovery for those sand units. The world first six- zones Smart completion were successfully installed in 2007 with the objectives of realizing increased recovery and a reduction in life cycle cost through real time monitoring and production optimization and a reduction in well intervention as well as reduction in HSE exposure. Challenges associated within the gas project included: Drilling through depleted and virgin pressure regimes of up to 8200 psi; Extended reach drilling of up to 7.3 km; Perforation; and, Installation of Smart-Completions in high-pressured gas environment. In addition to significant oil production, Champion West has been contributing to around 20% of BSP's gas production with a significant proportion coming from these recently drilled gas wells. This paper describes the well concepts adopted and the experiences developed throughout the project in drilling and installing Smart-Completions in this high-pressure gas environment.
Imaging Improvement of Fractured and Faulted Basement through Controlled Beam Migration Examples from Diamond Field in Vietnam
Authors: ElKady Nabil , Tan Yen Chu , Baker Rizal , Zhou Ziqiang Joe , Khoo Pauline , Tan Ann
Published: May 2016

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

The accurate determination of the velocity distribution in the subsurface is the single most important part in the long sequence of processing steps. Those accurate tomographic velocity models demand a state-of-the-art migration algorithms to honor the details that are needed in imaging the relevant complex structures. Controlled Beam Migration (CBM) is one of those techniques that exhibit an excellent impact on imaging Fractured and Faulted Granite basement. The velocity model that is used for depth imaging generally undergoes various iterations. It is the most difficult process, but yet also is the most important part of the velocity puzzle. Cell Based Tomography technique based on residual curvature analysis (RCA) was used for sediments velocity model building above the basement. In order to overcome the limitation of RCA tomography as it becomes less sensitive to velocity perturbation at deeper depth, Stack Sweep method has been performed to update the velocities inside the basement reservoir. This paper will concentrate mainly on the uplift of data imaging starting with Kirchhoff Pre Stack Time Migration passing through Kirchhoff Pre Stack Depth Migration and ending with Controlled Beam migration. CBM has a combined advantage of Kirchhoff migration (steep dip imaging) and Wave Equation Migration (multi-arrivals). It handles multi-arrivals, resulting in a cleaner image than Kirchhoff migration, and preserves the steep dips. Examples of the techniques are shown on data from Diamond Field, Offshore Vietnam with a discussion of specific issues that were encountered during processing.
Depositional Environment of the Upper Swan Sandstones, Caswell Sub Basin, Australia
Authors: Horton Phillip John , Harrison Paul , MacDonald Shona , Partington Mark
Published: May 2016

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

The Upper Swan sandstones represent a key exploration target in the Caswell Sub-basin and are the main reservoir units for the large Ichthys-Prelude gas-condensate field. The sandstones are present west of the Yampi Shelf margin from Leveque-1 in the southwest to Maret-1 in the northeast, and in the central portion of the Caswell Sub-basin extend to the northwest as far as Caswell-2.

Within the Caswell Sub-basin the Upper Swan sandstones are best understood in the Ichthys-Prelude gas-condensate field where twelve wells have been drilled to date. Interpretation of nearly 600m of conventional core, wireline logs, image logs and 3D seismic surveys have contributed significantly to the understanding of the depositional environment.

The Upper Swan sandstones is a lithostratigraphic term for sandstones that range in age from Latest Jurassic (Tithonian) to early Cretaceous (Berriasian) and are calibrated to the P. iehiense, K. wisemaniae and C. delicata Biozones. These sandstones are sourced from the Yampi Shelf and typically onlap and overstep Tithonian-aged mudstones. The sandstones are quartz rich, dominantly fine - medium grained with occasional very fine to coarse grained units present. Individual sandstone units range in thickness from centimetre scale up to several metres and are typically relatively featureless, homogeneous beds with occasional dewatering structures. Thin claystones typically centimetre to tens of centimetres thick, but up to 15m thick locally, are interbedded with the sandstones.

Core data suggests they were deposited as a series of stacked sand-rich gravity flows comprising repeated massive suspension (S3) and thin traction flows (T1 and T2) (dense flows of Lowe, 1982) in a shallowing Outer to Middle shelf characterised by vertically shallowing ichnofossil associations of Chondrites, Phycosiphon/Chondrites to Zoophycus/Phycospihon.

In the Prelude Field, the Tithonian and Berriasian-aged sandstones are mineralogically similar, with a complex diagenetic history consisting of compaction, quartz cementation, framework grain dissolution, precipitation of kaolinite/dickite, and the formation of authigenic illite. Authigenic clays appear to be of the greatest importance in the Upper Swan Sandstone in terms of reservoir quality with the data indicating the older sandstones tend to have higher total clay content and these are typically tight.
Integration of Downstream and Upstream Capabilities for Field Wide Production Optimization
Authors: Mardikar Asit , Van Donkelaar Edwin , Goh Keat Choon
Published: May 2016

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

The demand for oil and gas is ever increasing. At the same time much of the new oil is in challenging environments and is increasingly becoming more difficult to produce. This, together with exponentially increasing communications capacity and computing power, has led to several initiatives in the area of Digital Oil Fields, Smart Fields C_ etc. In all these initiatives, optimization on multiple economically relevant time scales plays an important role. The downstream refining and chemicals businesses have faced similar questions and have developed a well-established hierarchy for optimization on multiple time scales (Long Term Planning, Scheduling, Real-Time Optimization, Performance Monitoring, APC, Base-layer control) in which the scope, time scales, integration, interfaces etc. have been clearly defined.

There are several differences between the production system in the upstream and downstream supply chain. For example, diverse environments and workforces, significant and dynamically changing subsurface uncertainty and time scales of decades with respect to reservoir systems can characterize the upstream supply system. However, many principles of optimization and uncertainty management, such as the "division of time scales principle", are equally valid for upstream and downstream systems. This allows great opportunities to integrate and synergize upstream and downstream technologies.

This paper describes how such an optimization hierarchy can be constructed for field-wide production optimization, integrating downstream and upstream concepts. This paper will propose solutions based on the above concepts, while considering business decision requirements, engineering workflows and collaborative working. It will also indicate the challenges that need to be addressed to implement and maintain such applications reliably in the oil and gas production environment. A number of concrete field cases where (part of) this principle is successfully applied will also be presented.
An Integrated Sedimentological Approach to the Characterisation of an Incised Valley System: Example from the Miocene of the Malay Basin
Authors: Rees Andrew James , Lucas Peter M. , McCants Carson Young , Rae Stanley F.
Published: May 2016

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

The characteristic fill and sediment architecture of incised valley systems offer very attractive exploration opportunities, but require a fully integrated approach to fully quantify. Incised valley fill reservoirs are typically associated with rapid base level fall exposing previously deposited marine sediments to subaerial erosion and incision by fluvial processes. The accommodation space this incision creates is typically filled during the subsequent transgression by a complex mosaic of coastal plain and nearshore facies that produces reservoirs confined in time and space, but inherently highly heterogeneous in make-up. The problems imposed by acute reservoir heterogeneity are overcome by integrating traditional sedimentological methodologies with sequence stratigraphic concepts helping to define the allocyclic and autocyclic controls on sedimentation.

This investigation into tropical incised valley and estuarine depositional systems utilises high resolution core description, FMI/OBMI borehole images and conventional wireline logs from seventeen closely spaced wells penetrating the Miocene of the Central Malay basin. Detailed reservoir layering, depositional modelling and facies mapping has been integrated with seismic attribute analysis and static reservoir models to offer a unique insight into the reservoir architecture and properties of this inherently complex facies mosaic.

The resulting sedimentological model has led to improved stochastic modelling and improved reservoir deliverability. Successful marginal field developments in the 21st century mandate a reduction in subsurface uncertainties to mitigate cost over runs and successful commercial exploitation. This integrated approach to subsurface risk reduction has led to the successful commercial exploitation of the Malaysian asset.
Reconciling History Matching and Assessment of Uncertainty in Production Forecasts: A Study Combining Experimental Design, Proxy Models and Genetic Algorithms
Authors: Castellini Alexandre , Vahedi Arman , Singh Updesh , Sawiris Ramzy Shenouda , Roach Thomas
Published: May 2016

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

Description

The paper presents a method to tackle complex inverse problems where highly non-linear responses are involved. Geological models are built within an experimental design framework and are characterized by an objective function that estimates the quality of the history-match. The goal is to efficiently find combinations of parameters that minimize the objective function. Genetic algorithms are the main optimization tool in the workflow. In order to reduce the number of actual simulations and to accelerate the overall procedure, non-linear response surfaces, built with kriging interpolants at each iteration of the optimization routine, filter out unnecessary combinations of parameters. The models that reasonably honor the historical data are selected via cluster analysis techniques and provide an estimate of future production. The final distribution of the prediction variables defines the range of uncertainty conditioned to production history.

Application

The practicality of the workflow is demonstrated on the Malampaya field, a Gas Condensate reservoir in the Philippines. The field is a Tertiary Carbonate build-up situated offshore, below 800–1200m of water. It has been supplying gas from five subsea production wells since 2001 to three Gas-to-Power plants. Available subsurface data include a high resolution 3D seismic survey, five production wells with downhole pressure gauges and six appraisal wells with wireline and borehole image data, pressure and well test data.

Results

The strategy ensures multiple and significantly different history-matched models that provide estimation of the future performance of the reservoir. The coupling of space-filling sampling strategies, optimization algorithms, non-linear response surfaces and high performance computer clusters proved efficient in addressing the issue. In addition to a robust assessment of ranges in production forecast, representative P10, P50 and P90 individuals were selected from the portfolio of models for further analysis including optimization of development plan.

Significance

Understanding the impact of subsurface uncertainties on production responses is an integral part of the decision making process. A more accurate quantification of the uncertainty band around production forecasts contributes to better business decisions. Traditional experimental design workflows might be well suited for new field developments. However, when a field has been produced for several years, all models have to be conditioned to available production data in order to obtain meaningful predictions. This paper addresses the limitations of conventional techniques and provides a practical, structured workflow to reconcile the processes of data integration and uncertainty assessment.
Development of a Retrievable Single Trip Tubing Straddle Improves Success Rate on the North Slope of Alaska
Authors: Julian Jennifer Yvonne
Published: May 2016

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

Description

At Prudhoe Bay, Alaska, non-rig tubing repairs have become a viable alternative to rig workovers (RWO's). They provide an economic remediation for wells with production tubing by A annulus communication. Wireline-set retrievable straddles can eliminate tubing communication at a significant cost savings. The advantage over a conventional RWO is that there is no need to pull tubing, resulting in the well being returned to service faster.

Application

Single set or "one-trip" straddles were used historically at Prudhoe Bay, however, starting in 1994, a less expensive two run straddle design was adopted. A 2006 study of 263 permanent and retrievable tubing straddles set in 181 wells at Prudhoe Bay determined that single set straddles were far more successful and lasted longer than two set straddles.

Results, Observations, Conclusions

This paper describes the recent development, history, and success rate of a retrievable, single set tubing straddle for 4-1/2" and 3-1/2" tubing. It details the modifications required to convert a hydraulic set straddle pack-off to a one trip wireline set system. It also updates the analysis of more than 300 tubing straddles set since 1985.

The high success rate of the single set straddle has increased confidence in straddle operations at Prudhoe Bay.1. A single set tubing straddle has been developed to set in 3-1/2" and 4-1/2" tubing at Prudhoe Bay with an 80% success rate. This is a significant increase in success over the approximately 50% it has been in the last few years.2. Although there have been six failures, there is no one cause for failure. Continued analysis will improve candidate selection and pre-straddle diagnostics.3. Only one straddle has failed since successfully set, with a life of 1.4 years.A study of 263 straddles set between 1985 and 2005 indicates a conservative life of 3.5 years. It is likely that average life for single set straddles will be at least that long.4. A pre-straddle drift which mimics actual straddle length and OD is very important to ensure a successful set, particularly for wells with tight tolerances.

Significance

Single set tubing straddles can remediate tubing by "A" annulus communication at a tremendous in areas where rig workover cost is significant. They are particularly attractive in areas where rig workover cost is significant, such as offshore, remote, or arctic locations.
Applied Research Work on Density Log Responses in Thinly Laminated Bedded Sediments is Leading to a Better Understanding of Reservoir and Well Performance in West Africa
Authors: Stockhausen Edward Joseph , Condon Patrick
Published: May 2016

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

The application of joint industry and university research focused on quantifying density log responses from high angle and horizontal wells drilled in thinly bedded sediments is providing the basis for an improved understanding of Cretaceous shallow marine reservoirs in the Lower Congo Basin, West Africa. These reservoirs are dominated by a thick section of thinly bedded - alternating tight and porous siltstones - that are correlateable on a field-wide scale of several kilometers. The vertical well data in these reservoirs lacks the resolution needed to define the true nature of these thin beds. The research work shows that in vertical wells it is the source to detector spacing that drives the vertical resolution of the density log response. In horizontal wells, it is the depth of investigation that drives the log response. There is approximately a 3 to 1 ratio difference in vertical resolution between the density log response in horizontal and vertical wells. In these reservoirs, the density log data from horizontal wells is able to fully define most of the thin beds in these reservoirs which, are in the order of 6 inches (15.2 Cm) thick. A second part of the research shows how enhanced vertical resolution processing can improve the resolution from vertical and deviated wells. As the hole inclination increases to approximately 45 degrees and above, the enhanced vertical resolution processing begins to match that of the horizontal wells with standard density processing.

Updated reservoir simulation models, based upon new high resolution data from horizontal wells and reprocessed deviated wells are providing new insights into the performance of both producing oil wells and water injectors. The improved understanding of the fine scale reservoir properties is enhancing both operations and infill drilling strategy
Mapping of Social Communities and Issues in the Industrial Context
Authors: Du Laz Marie-Alix
Published: May 2016

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

1. Context

Total E&P Indonsie's activities are mostly located on the Indonesian part of the Borneo island - East Kalimantan province. The operations are concentrated in the Mahakam delta, a mangrove area of about 1500 km2, that has approximatively 60 000 inhabitants and an intense fishing activity. With a yearly production of about 2600 MMscfd, TI is a major social and economic actor in the region, and needs to map precisely its external stakeholders and their needs, in order to guarantee good relations with its local communities neighbors, and therefore smooth operations.

2. Methodology

The methodology used is called SRM+ (Social Relationship Management) and has been developed by Total headquarters. The principle is to bring the societal approach in line with its stakeholder expectations and to encourage the management team to share common views on local communities' issues and solutions.

The tool includes following steps:–conducting a comprehensive societal diagnosis–defining the history of relations with stakeholders–mapping the stakeholders and their expectations–defining clear areas for improvement to draw up a community action plan

3. Results

TI has conducted the methodology in one of its operational site, the Senipah base. It has allowed the site management and teams to share information about local communities issues that might not have been clearly identified, and to start looking for common solutions implicating the intervention of various departments and divisions. It has also allowed the creation of a map identifying clearly the major external stakeholders for which the site needs to elaborate a clear strategy of communication and actions, for example the groups of fishermen fishing in the Mahakam Delta, the inhabitants who installed close to the pipelines or the fishermen who installed shrimp pond farms in the Delta.
Wellbore Stability Prediction and Anisotropic Modeling in Highly Tectonic Basin, Eastern India
Authors: Azeemuddin Mohammed , Lee Hikweon , Mishra Premanand , Waghorn David , Ong See Hong
Published: May 2016

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

Wellbore stability analysis has been carried out for wells to be drilled in a highly tectonic area, involving overpressured sands, laminated shales and steeply inclined beds, in Eastern India. Data acquired on wells abandoned in the past with 52 to 73% NPT, have been utilized to generate static mechanical properties and in-situ stress information. The NPT was associated with kicks, stuck pipe, losses, washouts, and heavy reaming. Abnormal pressures were encountered below +/- 200m, including extreme overpressures in some areas. Well walk/direction problems were indicated at least in one of the wells. Most wells could not reach their TD and were abandoned prematrurely.

Considering the nature of the identified problems, safe mud weight windows have been predictied to avoid shear failure in the native formation, slippage along the dipping bedding planes, and mud losses. Both isotropic and anisotropic failure parameters were estimated and utilized in modeling wellbore stability.

The results of the wellbore stability modeleing were utilized in the field to drill a new well to a depth of 10,000 feet. The wellbore initially had to be side-tracked after encountering stability issues and losses. Pseudo-real-time modeling updates to the pre-drill model, based on data acquired while drilling and more recent pore pressure and bedding dips information, resulted in further refinement of the model in the overpressured zone. The implementation of the updated model, which included slight modifications to the wellbore trajectory allowed the wellbore to reach reached the planned objective TD without any major problems. Lessons learned and best practices adapted have been captured and reported. It has been observed from the results that the anisotropy in shale strength, changes in bedding dips and steeply dipping beds, could play a significant role and must be considered when drilling wells in a highly tectonic area.
Comparison of Petrophysical Rock Types from Core and Well Logs Using Post Stack 3D Seismic Data: Field Example
Authors: Cheng Francisco , Contreras David
Published: May 2016

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

The prediction of the spatial distribution of petrophysical rock types within a heterogeneous siliciclastic reservoir is affected by significant uncertainties when based only on well and core information. However, integrating additional constraints, such as 3D seismic attributes, can significantly improve the accuracy of the reservoir model. This paper shows the results of a well log based reservoir study with 3D seismic data that have been used to assess the petrophysical rock type distribution. The resulting rock type volume data provides an extremely valuable benefit in the current development of the field. The calculated petrophysical rock types were obtained using the Windland R35 equation which includes information collected from core data: pore throat size distribution, porosity, and permeability. Using the available core data, the workflow started by predicting both permeability and rock type curves at the non-cored wells. Several consistency checks and quality control revisions were applied to the results from these predictions in order to have a reliable relationship between petrophysical properties and rock types.

The resulting curves at the interval of interest were correlated throughout the field and calibrated with 3D seismic data. In order to obtain the correct parameter to enhance spatial rock type distribution, a multi-attribute analysis was performed in addition to a well log and seismic attribute cross-plot. The results clearly indicate that the application of this workflow is very valuable for determining new locations to be drilled either for production or injection.
From Vision to Reality - Delivery of Smart Fields in Asia Pacific
Authors: Quillien Yvon
Published: May 2016

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

Putting the Smart Fields vision into practice is not a one-size-fits all solution. As we all know, each asset has unique features. Geological, environmental and political challenges differ from case to case, as does the maturity of a field. At Shell, we have developed a company-wide methodology to bring smart fields elements into asset planning. It identifies and enables application of the most appropriate technology. It uses a structured process that helps our people to gain real ownership of the assets they operate. And, more broadly, to gain ownership of the delivery of the Smart Fields vision in their part of the business. During what we call the "Concept Selection" phase, initial screening matches the appropriate Smart Fields integrated solutions to the specific needs of the project.

The next step is to develop a Well, Reservoir and Facility integrated Management Plan that lays out how future field optimisation decisions will be made, underpinned by the optimum amount of data acquisition, modelling and interpretation. This plan is then brought to life by application of standardised workflows and introduction of enabling technologies. These include setting up Collaborative Work Environments to improve integration between the various technical functions in decision-making in a LEAN way. It is a dynamic approach that enables us to learn from existing asset operations as well as apply innovative R&D technologies for new projects. Shell in Asia Pacific has been the leading region for implementation, demonstrated by the delivery of New Projects that are currently being designed as true smart Fields; Examples of Shell operated New Developments in Asia Pacific are used as best practice examples for Shell EP.
Floating LNG - Has Its Time Come?
Authors: Faulkner Andrew , Pek Barend Johan Jan
Published: May 2016

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

Floating LNG (FLNG) has captured the imagination of engineers and LNG business developers ever since it was first considered over a decade ago. The concept is simple, but attractive: "Let"s put the LNG facilities directly over the offshore gas resource rather than processing and piping the gas long distances to shore". FLNG has huge potential to extend the portfolio of traditional LNG schemes necessary to meet the energy challenge of the 21st Century. Whilst technological and commercial challenges may have prevented FLNG succeeding to date, as evidenced by the fact that there are no FLNG facilities currently in operation; and whilst today's dynamic business environment, technological advancements, maturing ‘easy gas’ developments, heightened environmental scrutiny and overheated construction market have delayed FIDs for LNG projects, this same combination of forces and trends have led to the energy industry's renewed interest in FLNG.

Shell will share its perspectives on FLNG - reflecting on the learnings of past studies as well as looking forward to its plans over the next decade, including the expectation that one or more of its FLNG solutions will be in operation globally. The current technical concept with some of its key technical challenges, and the inherent safety approach applied throughout the design will be described. The process configuration of the topsides, the design of the substructure, the environmental characteristics, and the mooring system will also be covered.
Pore to Grid Carbonate Rock-Typing
Authors: Rebelle Michel , Umbhauer Francois , Poli Emmanuelle
Published: May 2016

Often considered as a complex task, rock-typing in carbonates comes down to achieve reconciliation between various sources of data, including high resolution logs, representative core data and dynamic data.

The simplest statistical relationship between petrophysical classes and geological facies should be sought for.

More than 30 years of experience in carbonate fields has reinforced TOTAL's expertise leading to a specific rock-typing workflow through upscaling management of all available information from pore to plug, plug to core, core to log and log to model grid-cell.

This paper details the 8 main steps of a Rock-Typing workflow which is indifferently supported by in-house or commercial softwares.

Introduction

The main Rock-Typing studies objective is to contribute to build a predictive dynamic model by an accurate 3D-distribution of geological facies being petrophysically meaningful through porosity, permeability, Pc and Kr.

To achieve this point, petrophysical properties have to rely on 3D-predictive variables (such as Geological Facies) depending on a quantification of statistical correspondances between Geological Facies (including sedimentological and diagenetical patterns) and Petrophysical Groups (rock units with homogeneous petrophysical behavior).

Carbonates rocks require a specific approach compared to clastic ones due to a higher level of complexity (facies heterogeneity, early and/or late diagenesis, pore topology, wettability changes).

A specific workflow based on 30 years of experience on world wide carbonate reservoirs has been developed, supported by in-house or commercial softwares. As a result of more than 10 years of R&D effort on sedimentology, diagenesis and petrophysical synthesis, relying on numerous case studies (REBELLE et al., 2000; REBELLE & AL NUAIMI, 2004; REBELLE et al., 2005; REBELLE & UMBHAUER, 2008; UMBHAUER et al., 2008), this resulting workflow reflects an integrated approach of different specialities as illustrated on Figure 1.
Managing Drilling Risk and Uncertainty Standard in Well Placement
Authors: Poedjono Benny , Isevcan Erhan , Lombardo Guy Joseph , Walker John Richard , McCulloch Simon
Published: May 2016

An effective anticollision risk management approach is essential for drilling safely in the congested subsurface environments increasingly common in today's drilling programs. Because there is as yet no industry-wide standard for collision risk assessment and management, many companies have developed their own standards, which can differ in significant details. In one recent project, both the operator and the directional drilling contractor had developed specific anticollision procedures. The challenge was to create a drilling program that satisfied the requirements of both standards. This paper describes the problems we encountered and the solutions we created to successfully design and execute a drilling plan satisfactory to both companies.
Advancement in Drilling, Increases Penetration Rates in Deep Hard and Abrasive East Texas Formation
Authors: Gala Deepak Manilal , Vieira Paco
Published: May 2016

This paper details the modifications performed and knowledge gained in 2007 and 2008 while drilling four underbalanced (UB) vertical gas wells in the Travis Peak formation of the western east Texas deep Bossier play in the Amoroso field, using jointed pipe. In spite of continuous improvements in drilling bit performance and better drilling practices, operators still face the "80-20 rule." Extremely hard and abrasive intervals represent about 20% of the total footage drilled, and they take about 80% of the time to drill out. Performance UB drilling (UBD) technology was used to increase the rate of penetration (ROP) through the formation at depths of 9,800 ft (2,987 m) and greater. The surface and the intermediate casing intervals were drilled conventionally. The next section (8 1/2-in. hole size, using hammer and tricone bits) was drilled using UBD techniques that used straight air or membrane nitrogen (N2).

The injection rates for compressed air or membrane-generated N2 ranged from 2,800 to 3,400 scfm, and the liquid rates during mist-foam drilling were 14 to 16 gpm (53 to 61 lpm). The section in the first well was drilled with three hammer bits and one tricone bit with an average ROP (including connection times) of 42 fph (13 m/h). Instantaneous ROP in the range of 350 fph (107 m/h) was observed with the hammer bits. A total of 2,378 ft (725 m) in 55.5 hr was drilled UB. During the entire UB phase, penetration rates were significantly greater than the offset records. The operator carried forward the lessons learned from the first well into the second well. A total of 2,750 ft (838 m) in 58.75 hr (using three hammer bits and one tricone bit) was achieved. Based on the second well's success, planning was initiated for the third well with additional improvements in bit design proposed. Enhanced hammer bit design, however, did not yield promising results; the decision was made to drill the remaining section with tricone bits. A total of 3,010 ft (917 m) in 61.7 hr was drilled UB using four hammer bits and three tricone bits. The fourth well was drilled using only tricone bits under UB conditions to compare the ROP between hammer bits and tricone bits. A total of 2,985 ft (910 m) in 76.9 hr was drilled UB using five tricone bits. Improved ROP and overall cost savings were the primary objectives for the client and were achieved. For the rig crew, drilling with compressed air or N2 was a new experience. Rig training was conducted before the drilling phase by the service company personnel.

Introduction

Conventional drilling techniques in hard-rock areas tend to be slow and are more expensive with increasing daily rig rates. The Travis Peak formation is located on the western flank of Robertson County, Texas, USA. The deep Bossier represents one of the most active onshore gas plays and has been assessed as one of the United States' largest gas fields, with estimated reserves of 4 Tcf of gas. UBD technology was used to increase the ROP at depths of 9,800 ft (2,987 m) and greater.
Downhole Fluid Density for Water-Base Mud Formation-Water Sampling with Wireline Formation Tester
Authors: Mas Cholid , Ardila Mario , Khong Chee Kin
Published: May 2016

A vibrating rod downhole fluid density device with the unique perpendicular oscillation modes provides in-situ fluid density measurements that improve a wireline formation tester's pressure, mobility, downhole fluid analysis, and sampling applications.

The measurement applications for the real-time water-base mud (WBM) formation-water sampling include contamination monitoring, in-situ fluid density, fluids identification, pressure gradient and fluid contact, and vertical compartmentalization. Field examples validate the measurements with the sample laboratory analysis and other measurements.

Introduction

Understanding the nature and composition of formation water is just as critical to the economics of field development as determining hydrocarbon composition. Chemical analysis of formation or connate water determines the scaling and corrosion potential of produced fluids, which determination is required for the design of completion and processing facilities. It also establishes the salinity for petrophysical evaluation, and fingerprints the aquifer for studies on basin hydrology. Water composition is important for production strategies involving inhibitor injection, wellstream mixing, process sharing, and enhanced oil recovery (EOR) injection (O'Keefe 2006; Godefroy et al. 2008).

The formation water samples are required early in the exploration /appraisal phase because water will not be intentionally produced from conventional drill stem testing (DST) and will not be produced until the field cut water at the later stage, thus too late for the planning. In the offshore or in environmentally sensitive areas, where margins for error are small and large capital expenditures must be spent upfront, proper planning is crucial.
Probable Reserves and Prospects for Exploration and Development of Oil and Gas Deposits in the Russian Arctic Seas
Authors: Piskarev Alexey , Shkatov Mikhail
Published: May 2016

The last decade offshore oil and gas has become the main source of growth of the world's hydrocarbon reserves. Special interest to the geological structure of the Russian Arctic Seas comes from very high hydrocarbon potential of their sedimentary basins, which are expected to take a leading role in future world power supply.

Geological and geophysical characteristics of the Russian Arctic Sea sedimentary basins allowed to estimate their hydrocarbon potential by comparison with the known world analogues. Due to difficult climatic conditions in Arctic, we consider only the potential resources of giant (more than 500 million barrels of oil equivalent) deposits. With a limited seismic data, data of gravity and magnetic surveys allowed to outline the main regional structures, to ascertain relations of the discovered hydrocarbon fields to the identified structures. Five major gas-condensate and gas fields are still discovered in this region: three (Shtokman, Ludlov, Ledovoe) in the Barents and two (Leningrad and Rusanov) in the Kara Sea.

Primarily structure of sedimentary basins of the Russian Arctic Seas was investigated by geophysical methods. One of successful methods of integrated interpretation of geophysical data is a simulation. Simulation is performed based on computer calculations of gravity effects producing by density heterogeneity of lower hemisphere. The following density models of the Earth crust used seismic and geological data related mainly to the basin sedimentary cover, as well as a few data on the deep seismic boundaries (Piskarev, 2004). Sites of direct geological observations relate mostly to folded belts and basement rocks in the periphery areas.

The structure of sedimentary basins of the Russian Arctic Seas is illustrated by a number of density models which are prepared by iterative computation method. Location of sections on which the simulation was performed and which are described below, is shown in Fig. 1.
Commitment To Coax Subtleties From Seismic By Means Of An Intelligent Integrated Approach - A Case Study
Authors: Kong Vincent Wai Tin , Carrillat Alexis , Gaither John Ross , Ibrahim Ahmad Bukhari , Abdullah Irmawaty , Hernandez NIna Marie , Abdul Rahman Mohd Ramziemran
Published: May 2016

Introduction

Much information is contained in the seismic reflectivity signal. The discernment between signal and noise, and the reduction of ambiguity of these signals is a major technical challenge. Interpreting lithology solely on normal seismic reflection strength has been well recognized to have pitfalls. This paper sets a case history of commitment by all parties involved to coax the subtle relevant data out from the seismic signals by means of an intelligent integrated approach.

It is current industry standard, with the availability of fast cost effective computer systems and data storage, to have outputs of a number of seismic data versions besides the traditional full stack seismic data. The ability to cohesively analyze all the available data in a timely manner makes the difference on the economics of petroleum exploitation from exploration through to the development phase. The result of each separate analysis should also converge for the deductions to be considered valid for interpretation.