bluuebunny/crossref_metadata_2025_split huggingface dataset:
Deep Diagnostics via Differential Microgravity Logging
Authors: Mever Thomas 
Published: February 2011

Abstract
Monitoring fluid movements and associated saturation changes over time is a key feedback element for enabling optimized reservoir management. Reservoir-wide inquiries made by time-lapse seismic acquisitions, though possible, are rare even in the world's biggest fields, and generally do not provide sufficient resolution or repeatability, nor a direct assessment of saturation changes. Conversely, conventional logging methods that do have high resolution and may provide the desired precision in saturation (e.g., pulse neutron logging and through casing resistivity methods), but do so on a localized basis, suffering from very limited depths of investigation. Thus, there exists a data gap, or opportunity, for geophysical techniques exhibiting moderate to large depths of investigation, with moderate or better resolution.
Time-lapsed gravity logging is one such method that if, given a significant "technology overhaul," could eventually close this gap. Subsurface measurements (versus those collected using various surface meters) benefit from enhanced signal-to-noise ratios by virtue of their immediate proximity to saturation contrasts and changes over time. Both practical results and analytic studies reported in literature establish gravity's intrinsic large depth of investigation. Furthermore, data relate directly and easily through bulk density to changes in fluid saturations.
The notion of reservoir monitoring via gravity logging is not new; however, measurement concepts and technology applied in emerging sensor development programs are. This brief synopsis gives insight to pursuits down one technology path – the BHg slim logging tool overviewed here aims to provide an order of magnitude improved performance compared to its precursor borehole gravity meter (BHGM), free of restrictions on well deviation and without a need to pull tubing.
The translation of gravity-centric tool performance (i.e., micro-Gal units) to g/cm3 density contrasts and component saturations requires specific problem geometry and reservoir properties, but is invaluable for providing a tangible illustration of tool capabilities to non-gravity practitioners.
Managing Geomechanics Principles for Proper Handling of Wellbore-Stability Problems in Shale and Depletion Effects on Formations While Drilling
Authors: Meng Fanhong (Frank) , Fuh Giin-Fa , Spencer Jeffrey A. 
Published: February 2011

Abstract
This paper describes two types of hole problems and wellbore stability solutions for drilling operations in North Sea fields: (1) severe shale cavings and wellbore collapse; (2) drilling through cap rock and reservoir formations impacted by large pressure depletion and reservoir compaction effects.
Field cases of wellbore collapses and failures in shale formations during high-angle drilling are presented along with a systematic program of comprehensive geomechanics investigation and evaluation necessary to prevent such events. The program includes analyzing drilling and log data analysis for rock strength and earth stress model construction, laboratory triaxial stress-strain tests on well core samples considering bedding plane inclination effects, 3D analytical modeling and 3D elastic-plastic numerical modeling analysis for determining optimum mud-weight (MW) windows for secure and stable well drilling.
Continuous well production can also present problems for in-field drilling as the severe pressure depletion and reservoir compaction will cause significant reduction in stresses and formation fracture gradient. These effects may occur not only in the reservoir, but may also extend significantly upward into the cap rock formations depending on the reservoir/formation stiffness contrast, reservoir size, thickness and depth, etc. Therefore, the optimum MW must be examined and recalculated based on the insitu stresses that can be altered by this effect. In summary, this paper will include the following: Analysis of actual drilling cases of severe shale caving and wellbore collapses/failures;Laboratory triaxial stress-strain tests on well cores considering bedding plane effects;Effective drilling guidelines based on modeling analysis of troublesome shale formations;Coping with reduced stresses and formation fracture gradient due to reservoir depletion and compaction effects;Use of wellbore strengthening material for drilling (and possible reduction in number of casing strings);Case histories of severe wellbore instability and lessons learned.
Application of Multizone Expandable Sand Screen Completions in Deepwater West Africa: Cased-Hole Functionality With Openhole Performance
Authors: Nicol Mark , Geddes Martin 
Published: February 2011

Abstract
Expandable Sand Screens (ESS) have been commercially available and applied in excess of 600 wells since 1999. ESS systems have performed well in a variety of application types, reservoir conditions and sand control environments. ESS systems were identified at an early stage of their development and implementation to have specific benefits and potential in order to complete multizone reservoirs in openhole in addition to the original goal of providing a viable alternative to openhole gravel packing. Such a multizone system has been developed and applied in various projects globally.
One such application where the ESS in a multizone reservoir that has achieved initial client objectives has led to subsequent further adoption and completion flexibility as result of performance. Initially specified as the preferred sand face completion for water injectors, the implementation of ESS in a West Africa deepwater field development has evolved significantly over 24 months.
The world's first 7.0" Multi-Zone ESS completion deployed and expanded from a floating vessel in deepwater, the project, in addition to setting some of the very early design goals, functional specifications and qualification requirements, has also driven some of the evolution of this openhole multizone sand face completion system. Performance of the ESS completion in water injectors from equipment supply, system installation, operational efficiency and subsequent injectivity drove the client completion team to open the application envelope by also applying the technology into producer wells. The producer wells have also yielded equally favourable performance results - operational efficiency, low NPT and excellent productivity.
The paper will detail the early design goals, functional specifications and qualification testing to allow system use as the base-case water injector completion, the evolution of the ESS system and adoption through the development of the deepwater project, describing lessons learned and overall performance of the ESS system in both water injector and producer application types.
Rate Allocation: Combining Transient Well Flow Modeling and Data Assimilation
Authors: Lorentzen Rolf J. , Saevareid Ove , Naevdal Geir 
Published: February 2011

Abstract
This paper presents an approach for rate allocation for individual wells by combining a transient well flow model and the ensemble Kalman filter. Specifically, we aim to utilize available high frequency measurements of pressure and temperature, focussing particularly on the early time period after changing influx conditions. The transition between two steady state flow periods implies natural excitation of the well flow, and during this phase an individual sensor experiences a golden age compared to the single value associated with a steady state. Thus, by taking proper advantage of the transient periods, it is reasonable to believe that important insight into the subsequent steady state conditions can be obtained.
We explore a couple case studies, indicating the feasibility of our approach and then draw some preliminary conclusions from our investigations.
Field Case Study on Formation Fines Control With Nanoparticles in Offshore Wells
Authors: Huang Tianping 'Tim' , Evans Brian A. , Crews James B. , Belcher Christopher K. 
Published: February 2011

Abstract
Various technologies have been developed in the industry to find efficient and cost-effective ways to control fines migration in producing wells. Migrating fines are often the source of formation near-wellbore due to their ability to choke a well's productivity by collecting in pore throats near the wellbore where flow velocity is high due to radial flow regime into the wellbore. It is important to minimize or prevent formation damage in the radial flow region around the wellbore to allow the well to operate at desired rate and bottomhole pressure. The typical recourse for formation damage resulting from migrating fines is expensive remedial stimulation treatments involving mud acid or hydraulic fracturing, which increases the well's operating cost.
This paper provides a field case study of using nanoparticles to treat proppant used on an offshore frac pack. The nanoparticles have significantly high surface forces, including van der Waals forces and electrostatic forces, to attach themselves to the surface of commonly used proppant. The nanoparticles that adhere to the proppant will adsorb migrating formation fines onto the proppant surface as the fines flow into the fracture. This will maintain well productivity much longer than untreated proppant in the fracture by preventing the fines from accumulating in the near-wellbore area. After the nanoparticle-coated proppant is saturated with formation fines, it can easily be cleaned up with conventional fluids and retreated with nanoparticles for continued capturing of formation fines.
The case history studies an offshore well that historically suffered systematic production loss due to migrating fines. The well was sidetracked and the new completion used nanoparticle treated proppant in the frac pack completion. After the treatment, the well's productivity was recovered and has maintained the recovered productivity for ten months without a formation fines issue.
Quantifying the Impact of Permeability Heterogeneity on Secondary Recovery Performance
Authors: Rashid B. , Bal A. , Williams G. , Muggeridge A. H. 
Published: February 2011

Abstract
A new and improved heterogeneity index is introduced that uses the shear-strain rate of the single phase velocity field to characterise heterogeneity in terms of its impact on performance. This index's ability to rank heterogeneous reservoir models is compared with that of the Dykstra-Parsons coefficient and the dynamic Lorenz coefficient. The new index is able to rank reservoirs, both accurately and quickly, based on performance for both miscible and immiscible fluids at a range of different mobility ratios. In contrast both the Dykstra-Parsons coefficient and the dynamic Lorenz coefficient are found to lack the sensitivity needed to be able to estimate the time to breakthrough of the displacing fluid and the recovery of oil at one pore volume injected.
High Performance Aqueous Insulating Packer Fluid Improved Flow Assurance and Reduced Annular Pressure Buildup in Ultra Deepwater Wells
Authors: Ezell R.G.. G. , Fontenot S.. , Robinson E.. , Cunningham L.. , Patrickis A.. 
Published: February 2011

AbstractDeepwater production well design and equipment installation present multiple challenges. One major problem is the uncontrolled heat transfer to outer annuli which can be detrimental to the integrity of the well. Annular pressure buildup (APB) could result in casing failure and heat loss from the production tubing causes dramatic loss of well productivity due to the deposition of paraffin and asphaltenes and could contribute to the formation of gas hydrates.Vacuum insulated tubing (VIT) was initially utilized in the deepwater well completions to help alleviate well failure caused by APB. The operator requested an alternative to VIT that would provide the following benefits:Reduced costs Minimization of APB or similar to VIT Increased flow assurance Ability to apply the downhole tools required to be installed in the production stringEase of placement was also an issue. Typically VIT takes special handling equipment, long lead times, and adds 10-12 hours of rig time for running of the production tubing.Customized high performance aqueous-based insulating packer fluid (IPF) proved to be a reliable alternative to VIT. A properly designed fluid having a density of 10.0 lb/gal and thermal conductivity (k) of 0.176 BTU/h ft°F was carefully prepared. The unique thermal-gelling characteristics of this state of the art fluid allowed for easy, rapid placement of the fluid in the well annulus. Once in the wellbore, the fluid has provided increased flow assurance as well as a reduction in APB thus resulting in increased well flow rates and improved profitability. Repeated field applications of this tailored aqueous IPF helped in achieving an overall cost reduction of more than 64% compared to utilizing conventional VIT. This paper presents detailed fluid formulations with laboratory data generated by specialized equipment, and discusses the fluid design criteria along with the reported data and economics.
Smart Well Re-Entry and Intervention in Offshore Angola
Authors: McNerlin B. , Shirmboh D. , Spearman J. , Price-Smith C. 
Published: February 2011

Abstract
The Greater Plutonio development in deepwater offshore Angola is BP's largest and highest producing subsea development in a sand prone reservoir. The development depletion plan stipulates 100% voidage replacement in multi-layered reservoirs; however, in a subsea environment drilling individual injectors into every produced zone is prohibitively expensive, so water injectors in multiple zones are completed as Down Hole Flow Control (DHFC) designs using wire wrapped screens across the reservoir sections. In June of 2009, problems were encountered during completion installation of the sixth DHFC water injector. Although the assembly was eventually deployed to depth and installed as planned, the problems encountered resulted in no injection into either the upper or lower zones. Coiled tubing intervention work was attempted to initiate injection, but further problems and rig time constraints led to the temporary suspension of completion operations. During the following months, a right scoping exercise was carried out on well recovery options, including recovering the existing equipment and recompleting if possible. Three months later the rig re-entered the well, whereby the coiled tubing intervention successfully cleaned the lower completion screen section exposing the lower zone, allowing rig based water injection to be successfully conducted. The lessons learned were incorporated into subsequent DHFC injectors, the next of which was completed in a project Best in Class time.
This paper discusses the general design of DHFC wells in Greater Plutonio, the difficulties encountered while deploying equipment into the sixth DHFC well of the project, the temporary suspension and recovery planning process, and the successful re-entry and coiled tubing intervention.
3D In-Situ Fluid Distribution Imaging at the Pore Scale as a New Tool for Multiphase Flow Studies
Authors: Youssef S. , Bauer D. , Bekri S. , Rosenberg E. , Vizika O. 
Published: February 2011

Abstract
In this paper we present a new experimental setup combining laboratory high resolution computed micro-tomography (MCT) with a flow microcell specially designed to reproduce in-situ multiphase flow experiments and monitor the fluid distribution at the pore scale. The objective is to describe the fluid saturations and distribution at different steps of the capillary pressure cycle (drainage and imbibition) while maintaining the sample under pressure in the cell to avoid fluid re-distribution. Experiments have been performed on a monomodal sandstone where the total porosity is resolved by the MCT. We compared successfully the saturation profiles calculated from the mean grey level of the 2D cross sections and the saturation profiles calculated by 3-phase image segmentation. The two above mentioned methods can be combined in bimodal pore systems to evaluate the fluid saturations in both micro (unresolved) and macro (resolved) porosity. Finally, we describe the distribution of each fluid at the different steps of the drainage-imbibition cycle and the influence of the pore geometry and interfacial tension on the oil trapping.
Stimulation With Innovative Fluid-Placement Methodology and World First Production Logging With Fiber Optic Enabled Coiled Tubing (CT)
Authors: AlDhufairi Mubarak , AlOmairen Khalid , AlGhamdi Saleh , Noya Vidal , Jacobsen Jan , AlSarakbi Samer , Ghani Adnan , Azrak Abdul Wahab 
Published: February 2011

Abstract
The coiled tubing (CT) e-line system is ideal to perform real time production logging (PL) in long horizontal wells, however, the wireline cable inside the CT can restrict the pump rate while the large volumes of acid normally pumped could potentially damage the CT pipe's integrity. Furthermore, using two different CT strings, one for pumping acid and another for performing the PL in real time is neither practical nor economical. A common current approach is to use a memory PL tool (PLT), with the associated drawback of missing/poor data quality and possible eventual misruns.
To overcome these challenges, a new CT multipurpose system has been developed, allowing real time PL and conventional applications. Leveraging on the telemetry offered by the fiber optic enabled CT (FOECT), already used for downhole measurements while treating in the M field; the new downhole assembly enables the use of standard PLTs in real time mode. At the surface, the converted optical signal is transmitted wirelessly to the PL engineer's portable computer; eliminating the need for conventional acquisition equipment and personnel.
In a world first application, the system was used in a land water injection well, after the stimulation job; obtaining the injection profile log with the same quality measurements as a conventional wireline conveyed log. Moreover, the data demonstrated a uniform injection profile.
The new multipurpose FOECT reduces the mobilization and logistics otherwise required, as well as the time and cost compared to existing alternatives. This new capability can be extended to other scenarios like offshore or remote environments, where operational costs have a larger impact. Ultimately, the system opens the door for performing diagnosis, treatment and evaluation in a single well intervention; making CT operations more efficient and providing more data for production engineers.
Well Completion Optimization in a North Dakota Bakken Oilfield
Authors: Zander Dennis , Czehura Michael , Snyder Daniel J. , Seale Rocky 
Published: February 2011

Abstract
First discovered in 1951, development of the Bakken formation in the Williston Basin has been problematic and inconsistent. However, technological advancements in horizontal drilling and completions in the past decade have steadily improved production results and consistency on a well by well basis. So much so, that the United States Geologic Survey (USGS) reported in 2008 that the undiscovered, technically recoverable oil in the Bakken was between 3 to 4.3 billion barrels.
How many fracture stages to run and how far apart to space stages in horizontal wells are prevalent questions asked by the oil and gas industry. This study provides insight into the advantages of various stage numbers and optimum stage spacing by analyzing up to 15 months of production results from horizontal wells targeting the Bakken in the Stanley Field, North Dakota. These wells were completed with open hole, multi-stage fracturing systems (OHMS) and production is compared to offset wells and field averages.
Advancements in OHMS completion and fracturing technology have enabled maximized production from this asset. The lessons learned and methodology can be utilized for other unconventional oil and gas plays around the world.
Viscous Oil Recovery Using Solids-Stabilized Emulsions
Authors: Kaminsky R. D. , Wattenbarger R. C. , Lederhos J. P. , Leonardi S. A. 
Published: February 2011

Abstract
An overview is given of the development and field testing of a non-thermal, viscous oil recovery technology that injects into a reservoir oil-external solids-stabilized emulsions (SSE) as a displacement fluid. The emulsion is generated on site using produced crude oil and water. Small amounts of added mineral fines are used to enhance the performance of naturally present surface-active components in the oil. Gas is dissolved into the oil to adjust the viscosity of the injected emulsion to be similar to that of the in situ oil. SSE fluid displaces viscous oil in a miscible-like manner with favorable mobility, which leads to to improved displacement and recovery. SSE is generally applicable to reservoirs with in situ oil viscosities of up to approximately 3000 cP and permeabilities on the order of one Darcy or more.
A series of laboratory tests were conducted to confirm the effectiveness of solids-stabilized emulsions as displacing agents. Specialized coreflood were used to measure emulsion stability, confirm process understanding, and to determine displacement efficiencies. After lab testing and reservoir modeling, a field pilot of the SSE process was designed, constructed, and operated. The field piloting confirmed the ability to generate and sustain injection of a solids-stabilized emulsion in the field and to propagate stabilized emulsions in the reservoir.
Innovative Well-Intervention Solutions Using Spoolable Connector
Authors: Howard Robert , Hriscu Joseph , Ehtesham Asif 
Published: February 2011

Abstract
Well intervention has seen significant growth in recent years because of increases in both new completions and workover operations on older wells. This has lead to development of larger and higher-grade coiled tubing (CT) for deeper and more challenging wells. The equipment, on the other hand, still needs to catch-up with the demands of bigger and heavier coil. Offshore installations present a challenge with weather and crane limitations. Onshore, road and bridge conditions often hamper shipment of large spools of CT. These issues lead to breaking the spool into two or three manageable sections and joining them on location. The increased cost, time, and equipment required to make a field butt weld make a mechanical connection the only acceptable alternative.
This paper presents the five-year development, testing, and deployment history of a mechanical, spoolable connector (SC) that has provided innovative solutions to one of the most challenging well-intervention problems (i.e., weight management of the CT string). SCs in sizes ranging from 1.5- to 2.875-in. OD were designed, built, and tested. A highly accurate finite element analysis (FEA) model was used to virtually test the design, resulting in industry-leading fatigue life. Correlation of FEA results with full-scale fatigue tests on 1.75- and 2.375-in. OD SCs, along with a case history of a 1.5-in. OD string, will be discussed.
A tapered OD (TOD) string with a SC enables two different outer diameters to be joined together on location, resulting in 30 to 80% weight reduction during transportation, compared to conventional strings. Combining it further with tapered wall thickness opens up new possibilities for deeper and more challenging deployments with depths exceeding 35,000 ft. Details on design and virtual testing of these strings is also shared.