bluuebunny/crossref_metadata_2025_split huggingface dataset:
Natural Fracture Detection, Characterization and Modeling Using the Event Solution Synergy Approach
Authors: Al-Omair Abdullatif A. , Elrafie Emad , Agil Mohammed , Colomar Francois-Michel 
Published: February 2011

Abstract
The detection, characterization, modeling and impact of natural fractures in prolific producing reservoirs are major multidisciplinary challenges. The task, from fracture detection through modeling, is conducted conventionally through limited multidisciplinary integration resulting in poor fracture realizations and understanding. Currently, there is no industry standard workflow that encompasses the wide spectrum of multi-discipline natural fracture detection techniques and modeling approaches. Meanwhile, the availability and range of well performance and formation evaluation data combined with improved reservoir characterization (static and dynamic) techniques have raised the awareness of not only the extent of natural fractures characterization and modeling but also their impact on fluid flow, history match and prediction.
This paper presents a workflow that integrates and leverages different field data types (static and dynamic) to strengthen natural fracture detection, characterization and modeling. In this approach, different data sources are combined and contrasted to derive a most likely natural fracture distribution, understanding and characterization in simulation modeling, including uncertainty range. This industry unique naturally fractured modeling workflow has been developed, adapted and enhanced through the collective experience of applying the Saudi Aramco, synergy-based "Event Solution" (Elrafie et al. 2007) integrated reservoir study approach.
This paper is supported by sanitized projects of large and mature producing reservoirs that firmly illustrate the success of this industry leading workflow and the impact of natural fractures on field production performance. Examples include; premature water breakthrough in reservoir regions and timescales that cannot be matched by matrix flow alone. Likewise, extreme oil rates that cannot be achieved through matrix permeability under measured pressure drawdown. These facts, coupled with static and geological insights are nested together to generate an integrated twenty-two components fracture detection and modeling workflow. Individually and in isolation, each data type component provides impractical and scattered fracture indications; however, the amalgamation of these varied data points narrows the uncertainty range of fracture realizations, yielding a robust and synergized fracture understanding and modeling.
This paper outlines best practices and critical factors of naturally fractured reservoir modeling and dynamic simulation. This includes a unique way of representing natural fractures in the numerical simulation model. Since there are many types of fractures, in this paper to simplify the illustration of the workflows we will target only the fracture corridors or the cluster of sub-vertical fractures that are normally extensive in their length and sometimes associated with shear faults.
Horizontal Underbalanced Drilling Technology Successfully Applied In Field AA- Libya: Case Study
Authors: Mohamed Ben Shatwan , Hani Qutob , Paco Vieira 
Published: February 2011

Abstract
Recently, underbalanced drilling (UBD) has been used with increasing frequency to minimize problems associated with invasive formation damage which often greatly reduces the productivity of oil and gas reservoirs. When properly designed and executed, the benefits of underbalanced drilling (UBD) are well recognized by the industry and there is increasing raise in interest in this technology. The benefits from UBD generally fall into two categories:
Cost reduction- including mitigation of conventional drilling problems as lost circulation, differential sticking, reduction in stimulation and cleanup costs, etc.
Value adding- including productivity improvement, increase in ultimate recovery, and real-time reservoir characterization while drilling.
Arabian Gulf oil Company (AGOCO), a major energy player in the Libyan oil industry, decided to pioneer the introduction of the new technology by embarking on a pilot project to drill 6 underbalanced horizontal wells in field AA. The Field is located in the Libyan Desert on the south east of Sirte basin. The reservoir consists of sandstone from the Early Cretaceous age. The field was first put on production in 1967. Since 1991 ESP pumps have been used for the production. The target reservoir, Member XX, is partly depleted oil bearing reservoir from the initial reservoir pressure of 3995 psi to about 2400 psi (5.3 ppg EMW). 3 out of the 6 well UBD campaign have been drilled so far. The first two wells identified the technology as an effective method to improve penetration and production rates. The third well built on the experience of the previous wells by emphasizing on minimizing formation damage and maximizing the production of the well. Another objective was the evaluation of production while the well is being drilled, eliminating the need for expensive post drilling production testing.
Shale Oil Potential in Saskatchewan
Authors: Schramm L. L. , Soveran D. , Schreiner B. , Kramers J. W. 
Published: February 2011

Abstract
With no commercial mines in operation, Canada's oil shales have not been widely recognized domestically or internationally. Nevertheless, Canada's oil shale resource has been estimated to be 15.2 × 109 bbl, an estimate that may rise with continued exploration across the country. Significant oil shale deposits have been identified in almost every Canadian province and territory, including Saskatchewan. Saskatchewan's oil shale resources are amenable to mining and surface processing but, as is the case with many of the world's deposits, environmental considerations will bolster the importance of developing new "game-changer" technologies that will reduce and/or replace the use of fresh water and dramatically reduce air emissions of CO2, SOX, and NOX. Significant R&D programs are now aimed at developing and demonstrating such new technologies for Saskatchewan's oil shale deposits, in order to make commercially viable a new source of Canadian "technology oil." This paper will provide an overview of oil shale geology, physical properties, and resources, highlighting Saskatchewan's oil shale and some of the novel recovery technologies that are being developed.
Optimize Shale Gas Field Development Using Stresses and Rock Strength Derived From 3D Seismic Data
Authors: Gray F. D. , Schmidt D. P. , Delbecq F. 
Published: February 2011

Abstract
Parameters of interest in hydraulic fracturing are the principal stresses, hoop stress and rock strength parameters such as Young's modulus and Poisson's ratio. Modern seismic inversion algorithms allow us to extract rock strength parameters. We show that they can be estimated between wells from seismic data. The azimuthal response of conventional and/or multicomponent seismic data is related to the stress field of the earth. By combining these methods, the magnitude of the principal stresses and the directions of the horizontal stresses may be estimated and then, hoop stress and fracture breakdown pressure can be approximated. These estimates may be used to guide field development away from existing wells.
Deploying the World’s First Commercial Dual Gradient Drilling System
Authors: Dowell J. David 
Published: February 2011

Abstract
Chevron is working with AGR Subsea, Pacific Drilling, GE Oil and Gas, and others to deploy the world’s first commercial Dual Gradient Drilling (DGD) System. The DGD system will be installed on a Pacific Drilling Samsung 12,000 Class rig currently being built in Korea. It is expected to begin operations in the Gulf of Mexico in 4th Qtr 2011. This paper will detail the design, fabrication, testing and preparations that are being made for that deployment.
Not only is significantly new hardware being added to the rig, but a new set of processes and concepts are being embedded in the drilling organization to take full advantage of the hardware. This has required the simultaneous development of two different, but linked, work streams: hardware and personnel. The “hardware” side of the work has concentrated on the integration of completely new equipment into the rig to make it DGD ready. This includes a subsea pump, a completely new riser, several riser “specialty” joints and all the rig modifications required to handle, run and support this new drilling system. The “people” work stream includes the development of drilling and well control procedures, well planning and the extensive personnel training needed to realize all the benefits of the technology.
This effort has impacted every facet of the Chevron deepwater drilling community. Chevron has reexamined the way rigs and drilling assets have historically been deployed. This has resulted in the development of a “Value Driven Drilling Schedule” to optimize utilization of the technology.
The DGD system could revolutionize how deepwater wells are drilled and how deepwater assets are explored and developed.
Managing the breakthrough of injected Nitrogen at a Gas Condensate Reservoir in Abu Dhabi
Authors: Abdulwahab Haytham , Belhaj Hadi 
Published: February 2011

Abstract
This study investigates the means of deferring the breakthrough of injected N2 and alleviating the impact of such on production rates and specifications as well as minimizing the required changes to the gas processing facilities. This aimed at assisting the ongoing efforts to transfer the Cantarell experience to Abu Dhabi, where large amounts of N2 gas will be generated and injected into a large gas condensate reservoir to partially substitute the recycling of lean gas. This will bring forward the opportunity to exploit lean gas by securing base load supplies before the start of reservoir blowdown, compared to the peak shaving approach currently practiced. Managing N2 breakthrough starts by better understanding the pattern at which N2 injection spreads into the gas accumulation. Based on the findings of initial subsurface and plant simulations carried out in 2008, N2 breakthrough in Abu Dhabi might be possibly deferred by segmenting the reservoir into a rich N2 region and lean N2 region. The approach assumes no thief zones will be faced and no channeling of N2 injected between the two regions is taking place. N2 is injected in the north region of the reservoir. The production of that region will be segregated and fed to a gas processing plant of lower NGL recovery, which essentially takes longer time to start suffering the deterioration of residue gas quality. The residue gas use can be limited to re-injection where the effect of below specification LHV would not be an issue. The rest of the reservoir feeds another gas processing plant of higher NGL recovery level from which an amount of residue gas equivalent to that of the injected N2 will be rerouted to the sales network. This scenario will significantly delay as well as downsize the requirement of a N2 rejection plant. There is technical and certainly economical advantage of deferring the installation of costly N2 rejection units. Such a requirement can be entirely eliminated if the sales gas specification can be relaxed considering blending with other gas streams of higher LHV, and in collaboration with gas customers, i.e. assessing their capability to tolerate feedstock of lower specifications. It must be noted that such school of thinking may not necessarily be eventually embraced. The chosen scenario will also depend on the final configuration, i.e, wells grouping and gas gathering, of the ongoing project.
Well Displacement Hydraulics -A Field Case Study and Simulation Investigation
Authors: Xu Zheng-gang , Maurera Jaimar , Shields Christian 
Published: February 2011

Abstract
Post-completion cleanup operations had left a seawater filled well that needed displacing to N2 via coiled tubing in order to achieve the desired underbalanced conditions for perforating. The unloading process is not steady state therefore dynamic simulator describing multiphase flow behaviour is essential to properly design and implement a displacement operation. To achieve a successful displacement a balance needs to be struck between CT run-in-hole speed, gas injection rate and the choice between continuous or intermittent gas injections.
This paper presents a field case study of a well displacement operation that only managed to displace half of the wellbore fluids when gas injection was critically interrupted and then after several days of using much higher nitrogen injection rates of up to 2000scf/min made no further significant progress.
The paper describes the application of numerical transient simulation to model the actual CT displacement in order to investigate the failures that occurred and gain a better understanding of how the displacement should have been performed. The predicted and measured parameters were compared to validate the numerical model. Different scenarios were simulated to optimize the displacement procedure. An effective solution to displacing the remaining half of the wellbore was first positioning the CT deep below the liquid level and then initiating gas injection. In this way, the liquid could was effectively lifted out of the well as slugs
The primary technical contribution of this paper is the application of dynamic simulation (new technique) to optimize fluid displacement using CT and N2 to lift fluids through the annulus with the added complexity of increasing CT and annular lengths with time. Furthermore, it shows the need to move away from the old "rule of thumb" steady state engineering practices.
A Mobile Multiphase Ram Pump for Onshore Oil Field Applications
Authors: Saadawi Hisham 
Published: February 2011

Abstract
Wells near the oil rim of one of the major oil fields in Abu Dhabi experienced a decline in wellhead flowing pressure. Several options were evaluated to produce these wells. These options included Electric Submersible Pumps (ESPs), conventional wellhead separation as well as multiphase pumping. A pilot project was implemented using a multiphase pump to produce the wells. The selected multiphase pump was of the positive displacement reciprocating type known as the RamPumpTM system.
Key challenges facing this project includes; no power source near the wellhead sites; oil rim wells have a broad range of operating conditions, high GOR wells and high H2S.
In order to allow the multiphase pump to be used for different wells, it was decided to have the pump mobile. Thus, the multiphase PumpPump unit, its driver and associated equipment were all mounted on flat bed truck.
Although multiphase pumping is now recognized as a state-of-the-art technology, this is the first time that a mobile multiphase pump was used in an oil field. This paper describes this unique application.
Waterflood: Surface Management Strategy
Authors: Pedro C. I. , Sutton J. D. , Zhumadilov A. G. , Dordoni F. , Rains D. B. 
Published: February 2011

Abstract
When the topic of "Waterflood" is presented for discussion, our primary expectation is that we are dealing with subsurface issues related to the efficiency of the flood: areal and vertical sweep, processing rate, pressure maintenance, etc.
In West Africa – offshore Angola, the operator came to the crude realization that elevated attention to the surface component of the water injection system was required to achieve the Asset Management objectives (reserves recovery). Twenty (20) years into the waterflood (+/− 3 billion barrels injected, and a current rate of +/− 550 mbwipd), problems with the water injection system revealed themselves as injection capability reduction and/or well tubular failures, resulting in costly workovers to reinstate water injection and to continue providing needed hydrocarbons sweep and pressure support.
With the absence of a robust surface water injection system remediation strategy, the number of well failures and/or reduction of injection were expected to increase. To remediate the situation detailed studies of the existing water injection system were performed, which included: understanding injection wells failure trends, injection water quality analysis, monitoring system evaluation, study of corrosion elements and review of existing injections wells metallurgy.
Results from these studies indicated that the main areas of concern were: ➢Degraded infrastructure➢Water injection quality out of specifications➢Failure trends – 8 to 9 years or 50 million barrels of cumulative water injection➢Severe well completion corrosion➢Poor monitoring program➢Deficient history records
To address these identified problems, a cross functional team was put together with the objective of safely and cost effectively, mitigate the reduction of water injection capability associated with failure of the injection system (pipelines, equipment and/or well failures) by: ➢Devising and executing a remedial program – Wells, infrastructure, equipment etc➢Recommending a long term strategy ■Well completion metallurgy■Water quality specifications■Chemical treating program■Monitoring program
Considerable improvements have been made to date through a business plan supportive of the Asset Management strategies and expansion of the devised water injection system management strategy to other assets within the operated concession.
Challenges in Design of Post Combustion CO2 Capture Facilities
Authors: Kumar Satish , Zarzour Othman , Gupta Anil 
Published: February 2011

Abstract
Abu Dhabi imports natural gas for domestic consumption since 2007 and at the same time injects natural gas in oilfields for enhanced oil recovery. Abu Dhabi presently emits significant quantity of CO2 to atmosphere due to its existing thermal power plants and other industries. An opportunity exists to inject CO2 instead of natural gas and release valuable supplies of natural gas for other uses while storing CO2 in acceptable geological formations to reduce greenhouse gas emissions.
MASDAR have plans for number of Carbon Capture & Storage (CCS) projects to capture large quantities of CO2 from flue gases, which otherwise are emitted to the atmosphere. Efficient recovery of CO2 from flue gases is not only a technical challenge but also it is the most expensive step of any post combustion CCS project. Approximately 20 MMTPA CO2 is aimed to be captured from existing and future power plants, Aluminium smelter, industrial facilities and oil & gas processing plants from 2020 onwards.
This paper presents some of the challenges faced by the design team in (a) flue gas characterization, (b) technology selection for post combustion CO2 capture, (c) provision of utilities, d) finalizing CO2 specifications and (e) assessing potential impact on the environment due to the carbon capture plant. Industry is presently flooded with claims of emerging technologies for capturing post combustion CO2. A brief overview of available technology and key issues — scale-up, high energy demand, validation of technology - is discussed.
Large capacity carbon capture plants are associated with high demand for heating and cooling requirements, which lead to engineering challenges for managing such requirements. Strategy adopted to meet these challenges is discussed and a potential solution is proposed.
Difficulties encountered in getting the design data, variability in flue gas flow and composition, flue gas treatment requirements are presented. Steps taken to characterize the flue gas composition for the design of the carbon capture plant are discussed. Results of flue gas testing and analysis are presented. Methodology adapted to identify the most promising technology for post combustion CO2 capture is described.
Site specific design challenges such as (a) flue gas characterization, (b) technology selection for post combustion CO2 capture, (c) required CO2 specifications, d) heat integration with the existing plant, e) availability of steam and cooling water f) parasitic CO2 recovery, g) unit optimization and h) options for reducing the energy demand are discussed.
Mechanics of Hydraulic Fracture Growth from a Borehole
Authors: Jeffrey R. G. , Zhang Xi 
Published: February 2011

Abstract
A numerical study of hydraulic fracture growth from a circular borehole under plane strain conditions is presented. The coupling of fluid flow and rock deformation plays a key role in the fracture reorientation process and in determining the curved fracture path formed. The fracture path is given as a function of both the nondimensional parameter β, which has been previously described in the literature and applies to fracture growth that is dominated by rock fracture toughness, and the recently derived nondimensional parameter χF, which applies to fracture growth that is dominated by fluid viscous dissipation. The results show that the values of β and χF determine the fracture trajectory as the fracture grows from the wellbore and eventually reorients parallel to the maximum far-field stress direction. Thus, for viscous dominated conditions that are typical of field application of hydraulic fracturing for stimulation, χF is a measure of the development of nearwellbore fracture tortuosity. A larger value of χF implies a stronger curvature and fracture tortuosity. The value of χF is reduced by increasing the viscosity and injection rate of the fluid.
Giant Field A ROS Study
Authors: Serag El Din S. , Al Hammadi Y. , Kalam M. Z. 
Published: February 2011

Abstract
A study was aiming to evaluate the remaining oil saturation (ROS) behind the flood front using Liquid Trapper technology and open hole logs. Four (4) wells were included in this study, two in the South and two in the North of the field. These wells were selected in areas highly flooded by peripheral water injection. The objective is to improve the description of ROS and better estimate the oil recovery efficiency from the field.
The Liquid Trapper Coring technique is used to provide more accurate oil saturation data for the reservoir model. It was used in this project in particular to evaluate the remaining oil saturations in the flooded reservoir zones.
The Liquid Trapper Coring is a technique to capture any oil that is expelled from the core (due to pressure change) by gas expansion as the core is raised to the surface. This volume of escaping oil can then be calculated over selected intervals and incorporated into the standard saturation analysis performed on the whole core sections. The oil saturation determination from core would give the expected remaining oil where as the oil captured in the trapper barrel would indicate any movable oil in the reservoir.
The inner tube of the Liquid Trapper is made of stacked modules, 1m in length and each made up of closed ‘cells’. The cells allow capturing of the expelled fluids and segregation of oil, water and gas due to gravity difference. The fluids in the cells surrounding the core are collected to be added to the volume of oil saturation in the core. The volumes were measured in the laboratory by centrifuge and were added to the saturations measured using Dean Stark method.
This case study presents the results and uncertainties of using Liquid Trapper Technology in ROS determinations behind flood front of water invaded carbonate reservoir zones. An assessment of this new technique, and its pitfalls in onshore reservoir applications is compared with conventional sponge core coring.