bluuebunny/crossref_metadata_2025_split huggingface dataset:
Fracture Modeling for Optimum Wellbore Integrity Enhancement
Authors: Kostov Nikolay , Gosavi Shekhar V. , Kulkarni Kaustubh , Dasari Ganeswara 
Published: November 2016

Abstract
We present a method for modeling the transient growth of drilling-induced fractures through a porous medium in the near wellbore region. Understanding the early time fracture growth behavior, and related near wellbore stress state, can provide an effective tool to improve the treatment selection through parameters such as particle size distribution and ideal drilling fluid rheology. Also, it will help with field diagnostics for various lost circulation treatments and lost return events.
ExxonMobil Upstream Research Company and SIMULIA® co-developed fully-coupled hydraulic fracturing modeling capabilities. The model was benchmarked with known solutions to analytical fracture growth regimes and validated with a laboratory scale experimental setup of hydraulic fracturing. The model allows for fluid leak-off from the wellbore and fracture faces into the porous medium for an arbitrary injection schedule.
The time-dependent fracture growth and interaction between the stress concentration region near the fracture tip and the wellbore result in a non-linear behavior of the near-wellbore stress state during early time fracture propagation, which was not possible to capture with static models. This analysis allows for recommendation of an optimum fracture width for maximum increase in wellbore integrity in the target formation. This is done by selecting the fracture width at the mouth, at which the desired increase in the near-wellbore tangential stresses has been achieved as to prevent initialization of further fractures. The model was applied to a field scale example and the predicted integrity gain from fracture plugging agrees well with observations.
WAG Management with Foams: Influence of Injected Gas Properties and Surfactant Adsorption
Authors: Batôt G. , Delaplace Ph. , Bourbiaux B. , Pedroni L. G. , Nabzar L. , Douarche F. , Chabert M. 
Published: November 2016

Abstract
In reservoir applications, due to their ability to restrict gas flow, foams are among the most promising and cost-effective means to alleviate the drawbacks associated with gas-based EOR processes. In porous media they can be seen as finely-textured bubbles of gas such as nitrogen, carbon dioxide, or/and methane, dispersed within a brine containing surfactants. The objective of this work is to probe the impact of the gas properties on foam efficiency and oil displacement.
Coreflood experiments were conducted on Fontainebleau and Clashach sandstones. The injected gases were mixtures in which CO2 fraction was changed from 12% to 100%. Different pressures were applied to evaluate the influence of gas density. Thus, the impact of oil saturation on foam efficiency could be assessed under both immiscible and miscible conditions. Simulations were performed to compare oil production improvement between Simultaneous Water And Gas injection (SWAG) and Foam-Assisted SWAG processes. A 1D horizontal model was adopted to evaluate the impact of gas mobility reduction, and a 2D vertical model to assess the impact of gravity override.
In the absence of oil and for each injected gas mixture, the impact of pressure on the steady state gas relative permeability in presence of foam, i.e. Krgf=vgμgas/(K∇Pfoam), revealed a unified behavior for the whole range of foam qualities. Regarding the effects of gas composition, Krgf was found to increase with the CO2 fraction. At the lab scale, the measured oil recovery factor does not take into account field scale heterogeneities. Thus, coreflood-calibrated simulations are essential to predict additional recovery at the reservoir scale. The numerical study provides helpful indications that may serve for selecting/designing a foam recovery process. It turns out that SWAG should be preferred to foam in reservoirs with low thickness and tilt, and/or with low vertical permeability. On the opposite, a foam process can be more efficient than SWAG in reservoirs that are subject to strong gas gravity segregation. In this situation, the economic success will essentially depend on the ability to minimize the surfactant adsorption.
The Origin of H2S in the Arab Reservoirs in Abu Dhabi
Authors: Nederlof Peter , Kaczorowski Norman , Lawrence David 
Published: November 2016

Abstract
Two different sources of H2S have been identified in the ultra-sour gases in the Arab Formation in Abu Dhabi, based on sulfur isotope measurements of both anhydrites and H2S. In the Upper Arab reservoirs, H2S appears to be generated in-situ from intra-Arab anhydrites, leading to variable, but relatively low H2S concentrations. Sulphur isotopes suggest that the Lower Arab reservoirs receive H2S from anhydrites in the Hanifa or possibly even deeper Formations. The different sources of H2S clarify the highly variable fluid compositions in the Upper Arab reservoirs, while active migration of H2S from deep sources would explain the observed compositional gradient in the Lower Arab reservoirs. The in- situ generated H2S in the Upper Arab reservoirs is unlikely to increase during the production lifetime of the field; the externally generated H2S could increase when depleting reservoir pressures (re)-activate the faults that form the migration pathway of the H2S. The extent of the TSR reaction, and thus the H2S concentrations in the gas, can be estimated by measuring molecular proxies that can be thermally extracted from core and cuttings samples. This study is the first to document the successful use of molecular proxies to accurately estimate H2S concentrations in the gas contained in individual, isolated reservoirs.
Seismic Wave Attenuation: Promising Attribute for Fluids, Fractures and Tar Mats Characterization in Abu Dhabi Oilfields
Authors: Bouchaala Fateh , Ali Mohammed Y , Matsushima Jun 
Published: November 2016

Abstract
Seismic wave attenuation can be used to enhance geophysical interpretation in the reservoir zones, this has great benefit for oil and gas industry. Getting accurate attenuation profiles is prominent to get correct geophysical interpretation, however this is not an easy task since the methodology is not enough mature yet. The difficulty is higher for complex media like those composed carbonate rocks, such media are known to be highly heterogeneous. The subsurface of Abu Dhabi region is known to be mainly composed of carbonate rocks.
We developed a new method to estimate the intrinsic attenuation and scattering separately, from downgoing waves of VSP data. This new method is based on seismic interferometry technique and it is less sensitive to upgoing waves compared to classical methods. We estimated attenuation from sonic waveforms by using new method well adapted for such type of data, this method was successfully applied in previous studies.
We got accurate and high-resolution scattering and intrinsic attenuation profiles from five wells belonging to five oilfields located in Abu Dhabi region. Compared to previous studies carried out in siliciclastic media, the attenuation shows high variation over the depth, and the scattering shows significant contribution on the total attenuation. We explain this by the high heterogeneity characteristic of carbonate rocks.
We found very interesting correlation between the attenuation profiles and the other petrophysical logs, such as the sonic and oil saturation logs. The scattering shows a good correlation with the fractures, and intrinsic attenuation shows a good sensitivity to the fluid existence. So the combination between the scattering and the intrinsic attenuation is a promising and can be very useful for the petroleum exploration, especially in the case of Abu Dhabi reservoirs known to be highly fractured.
Debottlenecking of FPSO Facilities by Compact Separators
Authors: Krebs Thomas , Balk Wouter , Verbeek Paul , Akdim Reda , Kruijtzer Govert , Ibohouten Boubker , Ogazi Isaac , Okoh Godwin , Arntzen Richard , Shell AS Norske , Paranjape Mrudula 
Published: November 2016

Abstract
The Bonga FPSO was designed to process 280 MBLPD gross liquid, constrained by the three-phase low pressure (LP) separator capacity. The projected production forecast indicated that additional future volumes of produced fluids from the Bonga field could exceed the design capacity of the installation. FMC's Inline PhaseSplitter was identified as a solution for debottlenecking the three-phase LP separator liquid handling capacity. The PhaseSplitter is a compact pipe-based cyclonic separator that splits the feed flow into a gas stream with limited liquid carry-over and a liquid stream with limited gas carry-under. The performance objective for the PhaseSplitter is 70 % or more gas removal while keeping liquid carry-over in the gas outlet below 1 % volume fraction.
In this paper, we report results of a technical qualification program (TQP) for the PhaseSplitter as a debottlenecking tool for the three-phase LP separator. We used a down-scaled 3 inch pipe of the PhaseSplitter as compared to a 24 inch full-scale field unit. A model fluid whose physical properties resemble the Bonga fluids was used, thereby giving credence to the test results. A test matrix covering a range of representative feed conditions was probed: gas volume fraction (GVF) 75 - 90%, water cuts 20 - 80% and inlet momentums 4500 - 11000 Pa. We measured the percentage of gas removed from the feed and the amount of liquid carry-over into the removed gas as function of the flow split to the gas outlet.
The results show that for almost all test conditions, acceptance criteria that were set for the PhaseSplitter were met, i.e. 75 - 80% gas removal and liquid carry-over with the gas less than 1%. Gas-liquid separation performance gradually decreases with decreasing momentum and GVF in the feed. We observed no dependence of separation performance on the feed water cut. We plotted the results as function of the normalized flow split showing universal trends. These trends provide a means to control the separation performance by monitoring the pressure drop over both outlets. We conclude that the PhaseSplitter delivers a robust performance under steady-state conditions over a wide range of operating conditions.
Enhanced Multilateral Reservoir Monitoring for the First Time in Offshore Abu Dhabi Utilising New Well Intervention Technology
Authors: Bilbeisi J. , AL Mehairi O. , El Sayed M. , Al Mansoori A. , Berrim A. , Keshta O. , AbdelFattah Y. , Sudhakaran S. , Chehabi W. , Smith A. 
Published: November 2016

Abstract
Changing oil field development economics has pushed the trend towards developing multilateral wells to increase production and maximize oil recovery utilizing advanced well configurations. However, to focus on maximizing the value of multilateral wells by addressing reservoir and production challenges; efficient reservoir management has remained a challenge. Accessing multilaterals has not been possible with conventional Coiled Tubing logging techniques. Current available technologies for deploying Production Logging services in the multilaterals are of less success, due to hardware limitations.
The challenge was to access slim hole laterals from the mother bore in order to perform reservoir surveillance activities namely production logging as well as acidizing operations in laterals previously inaccessible. The information gathered from this intervention would improve the overall understanding of the reservoir and well behavior thus enabling the operator to manage the multi-lateral wells’ individual drains, ensure production assurance and sustainability and revisit the development plan for the tight reservoirs based on proper reservoir evaluation.
With the introduction of a new lateral intervention tool, the operator was able to successfully access a lower drain drilled from a window in the casing with efficiency and certainty. The smaller size tool used on this operation had an OD of 2 1/8", which is ideal for accessing laterals in wells with slim hole completion.
The tool helped in accessing the lateral and provided the operator the opportunity to perform production logging operations. This had previously not been possible with conventional technology which was attempted numerous times without success.
The need for mobilizing a rig was prevented in addition to the reduced foot print of the required equipment and personnel required reflect substantial reductions in time and cost for this intervention.
This paper introduces the knowledge learned from the world’s first multi-lateral accessibility and production logging operation in the UAE by applying a new multi-lateral accessibility on Electric Coil Tubing through detecting the multilateral window and activating a powered arm for entry into the lateral section.
Impacts of Dense Phase Flow on Pipeline Capacity - Case Study
Authors: AlRaeesi Fatima , Al Kaabi Nouf 
Published: November 2016

Abstract
In view of ADNOC's vision towards optimization, efficiency and profitability, GASCO along with its Operating Companies is committed to ensure process design optimization. In line with this a project was implemented using the same existing pipeline to accommodate the additional feed gas coming from offshore production facilities.
A 30-inch dense phase pipeline is originally designed to accommodate a normal capacity of 200 MMSCFD Feed Gas with an operating pressure of 148-97 barg (varies based on transported gas composition). The design capacity of this pipeline is 530 MMSCFD. The feed gas supplements the LP gas already being delivered through the OAG facilities and this brings the total of LP OAG and HP Integrated Gas Development (IGD) gases to 1000 MMSCFD.
Several studies were conducted such as dense phase pipeline transient hydraulic analysis to ensure the pipeline's ability to handle the additional capacity running at 207km long.
Additional capacity can be handled in the existing 30-inch pipeline in terms of operational modification within the operating envelope; for example, the inlet pressure to the pipeline is limited to a maximum of 152 bara. The analysis for this study proved that the combined OAG and IGD feed gas does not cause the pipeline to experience temperatures close to the minimum design temperature of -10°C. The limited design capacity was overcome by increasing the operating pressure in order to achieve the dense phase region and the new capacity.
A fluid within the dense phase region has significant benefits, primarily emphasizing on a low CAPEX and OPEX, amongst which are the following: Lower fluid velocitySmaller inside diameterHigher potential for NGL extractionSlug Catcher is not required
First Time Offshore Abu Dhabi-Successful Appraisal Drill Stem Testing Operations in Extreme Sour Environment - A Case Study
Authors: Iabbassen N. , Al-marzouqi A.M. , Slatewala H.S. , Jimenez J. , Karim H. Abdul , Sax K. , Shateri A. Al , Sutherland R. , Barrow D. , Ameri F. Al , Huda S. 
Published: November 2016

Abstract
As part of of the studies being done aiming to secure bigger gas and oil resources in the UAE, several fields have been undergoing extensive appraisal & evaluation efforts over the past few years. Starting from a review of seismic, petrophysical and well test data from discovery wells, new appraisal wells have been drilled, logged and tested to refine reservoir models and evaluate static and dynamic reservoir properties.
With a focus on determining economic viability, productivity and reserves, well testing is a key source of information, yielding fluid samples, productivity, formation mobility and prodiving key indications about optimal completion options such as well inclination or completion method.
To demonstrate the existence of moveable petroleum in a reservoir and/or to provide an indication of the potential productivity of that reservoir, well testing is of particular importance to obtain critical information about undeveloped reservoirs. Well testing provides a full understanding of the attributes of a well so that it can be operated profitably and efficiently.
A recently drilled appraisal well includes deep oil / gas reservoirs containing up to 38% of hydrogen Sulfide (H2S) and 7% of carbon dioxide (CO2) was successfully tested using Drill Stem Test (DST) in Abu Dhabi offshore field.
In order to successfully appraise this field with its specific nature of reservoir fluids that makes all drilling and data gathering operations extremely challenging, many problems had to be solved in well testing techniques. It had to focus on optimal fluids containment and minimization of release. To achieve those aims, several modifications of the equipment were required.
It required extensive risk assement sessions with all service providers and rig contractor, in addition to the real time monitoring of all surface and downhole parametres. A systematic multi discipline planning approach with attention to detail, rigorous planning and team work, were some of the key success factors in delivering the objectives in a safe and efficient manner.
Design and Analysis of Leg Jetting System for Offshore Jack-ups Rigs
Authors: Roy Mintu , Fandy Hesham 
Published: November 2016

Abstract
Jack-ups used for offshore wind turbine installation pose numerous challenges during extraction. The seafloor terrain differs from location to location and the entire design and installation needs to be planned according to the specific requirements of each project. This research was specifically focused on the challenges faced in extracting the spudcan and proposes a jetting system design that can assist in smooth extraction. The research tackled practical challenges that affect the performance and safety of leg jetting systems, a practical leg jetting system design is suggested suitable for wind turbine installation vessels. The design was simulated where different case scenarios at different water depths and spudcan penetration levels were checked for its safety and operation.
Safely Landing the First Oil Producer in the Barents Sea
Authors: Tosi Gianbattista , Stensland Dag , Winterton David , Zappalorto Luigi , Wang Haifeng , Dupuis Christophe , Denichou Jean-Michel , Horstmann Mathias 
Published: November 2016

Abstract
Goliat was the first oil discovery in the Barents Sea and holds 174 million barrels of recoverable oil. It is operated by Eni Norge (65% share, with Statoil holding the rest of the equity). Finding oil is important, but safely and efficiently developing it is critical. The remoteness of these frontier projects amplifies the consequences of any delays or issues. Risk prevention and mitigation is the object of particular attention in this new frontier area. Landing the first producer was a particularly sensitive operation, requiring a safe stop a few meters above the top of the reservoir to reduce the risk of landing the section within the reservoir gas cap bearing sandstone.
A geometrical landing would be limited by a depth uncertainty of more than 10 m true vertical depth (TVD): relying on surface seismic information is subject to seismic time-to-depth conversion and the inherent limited resolution of seismic data. Taking these uncertainties into account normally requires setting the casing long in advance of the reservoir top, giving way to a much longer portion of the reservoir section exposed to the overburden shales, with consequent 8 ½’’well bore instability issues and risk of plugging the completion screens.
For the Goliat well, the operator adopted a different approach to land the objective while preventing the risks of setting casing too soon or too late. A new ambitious objective was set: stopping and casing as close as possible to the reservoir, but no closer than 5 m TVD. This could only be done by using the latest generation of deep directional resistivity (DDR) logging-while-drilling tools in the 12 ¼" section, increasing both the precision and the accuracy of the landing by relying on a direct detection of the reservoir top before drilling into it.
The DDR real-time automatic inversion of the subsurface layering revealed the top of the reservoir from 19 m TVD below the bottom hole assembly, a new record. By tracking the top boundary, even at a steep inclination near 70°, the operator confidently stopped drilling when the bit was 6 m TVD above the top of the reservoir, as planned, safely minimizing the distance to be drilled in shales before intersecting the reservoir. The distance to the reservoir was verified in the next section drilled.
The use of DDR for landing wells accurately either above or just below a top reservoir is now a proven powerful option for drilling programs in which risk prevention is required at the top of the reservoir.
Oilfield Build Own Operate BOO Projects - A Good Execution Strategy for the Current Low Oil Price Environment
Authors: Bernstein D. , Gonzalez C. , Heikal M. 
Published: November 2016

Abstract

Objectives/Scope
In the current low oil price environment, oilfield Build Own Operate (BOO) and Build Own Operate Transfer (BOOT) projects deserve consideration. Although generally the objective of BOO and BOOT projects are to reduce upfront capital costs and transfer risk to the BOO contractor, BOO and BOOT projects also offer excellent opportunities to incentivize innovation and reduce project lead time to complete, lowering project life-cycle costs and accelerating project returns. If the BOO project is structured properly - safety, quality, and reliability are not sacrificed.

Methods, Procedures, Process
This paper compares and contrasts BOO and EPC projects to describe advantages and tradeoffs for successful application of BOO projects. The performance of the Kuwait Oil Company (KOC) EPF-120 project in North Kuwait is reviewed, as a successful example of the application of BOO projects in the oilfield. The EPF-120 project is a BOO grass roots centralized Early Production Facility that processes 120,000 BPD of crude oil, 84,000 MMSCFD of gas and 80,000 BPD of produced water. The project has now been in service for the full term of its five years operations contract.

Results, Observations, Conclusions
The typical structure of BOO projects and EPC projects are described, and conventional EPC projects are compared to BOO projects. Incentives and disincentives for innovation are discussed. Typical project timeline for EPC projects will be compared to BOO project timelines. Mechanisms to achieve quality, safety, and reliability are provided. As an example of the opportunities that BOO projects offers, operations, maintenance, environmental, and safety performance of the EPF 120 project is reviewed, and examples of innovation implemented for the EPF 120 and for other BOO projects are provided.
Additional costs of BOO projects - namely risk and financing are provided and compared to potential reduced life cycle cost and reduced project completion timeline. Operating challenges to execute a BOO project in an existing oilfield are presented. Trade-off between flexibility/innovation and specification/standardization are also discussed.

Novel/Additive Information
BOO is a solution in the oilfield to provide innovation and improved schedule without sacrificing quality, safety, and reliability. The skills required to successfully execute a BOO project will be detailed and include the following: process engineering and Front End Engineering Development (FEED) skills, capital and operating cost estimating capability, Engineering, Procurement, and Construction Management (EPCM)