bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Case Study Using a Remotely Controlled Downhole Valve for Completion Installation
Authors: Oddie Keith , O'Hara John , Paz Luis 
Published: June 2014

Abstract
Offshore platforms and subsea wells often are designed to enable interventions to be performed during the completion phase of the well construction. An example of the above is the deployment of a deep-set plug (as a temporary barrier) to set the production packer and test integrity of the production tubing.
Each intervention has a direct cost due to rig time and the risks mitigation associated with the manual rig-up and testing of the pressure-control equipment addressing health, safety, and environmental challenges becomes a high priority that will consume time during the planning of operations. Operational risk is present due to the mechanical methods used for deployment and retrieval of the plug, and in deviated well designs, this risk will be even more severe due to the implied impact.
Using a case study in Equatorial Guinea, West Africa, this paper demonstrates how barrier provisions with remote open/close technology capabilities enables interventions to be removed from a completion design. The technology described was used in a horizontal subsea producer well drilled to 3,460m, and will illustrate how combining downhole electronic control with a full-bore hydraulically operated barrier valve removes any need for running control lines to surface. Surface applied pressure and time combinations were used to command remote actuation of the valve. The factors that must be considered when determining these commands are also discussed.
The successful field deployment discussed in this case history illustrates how applying remote open/close technology provided the opportunity to challenge conventional completion methodology and was capable of providing significant cost savings as well as simplifying operational strategies.
First Successful Commercial Application of Dual Gradient Drilling in Ultra-Deepwater GOM
Authors: Ziegler Robert , Sabri Mohd Saiful , Idris M Ramdan , Malt Roar , Stave Roger 
Published: June 2014

Abstract
A previous attempt to drill an exploration well in ultra-deepwater in the GoM did not reach its objective due to an inability to maintain a Water Based Mud system light enough to maintain circulation. For the next round of exploration drilling, a system that allowed dynamic management of Annular Friction Loss (AFL) was required in order to stay within the narrow margin between pore and fracture pressure gradients.
Conventional Rotating Control Device (RCD) based Constant Bottom Hole Pressure (CBHP) management systems were not suitable, as no drilling fluid light enough to manage the AFL with an added backpressure could be applied for this campaign.
A "Controlled Annular Mud Level" type DGD system was successfully applied on this well in 2260 m water depth. This method compensates for the annular friction pressure by reducing the riser level according to the circulation pump rate. The system was also used to manage downhole pressure for cementing operations to mitigate losses and ensure good cement integrity with full returns during the cementing operation.
The riser level was decided in the drilling program and adjusted according to PressureWhileDrilling (PWD) Readings. It could also be demonstrated that lowering the riser level increased ROP, whilst raising it again decreased ROP. The sensitivity for kick detection was greatly improved as the effect of rig motion on surface volumes was eliminated.
The paper presents the project approach to deliver results and the technology applied. Results achieved on this well will be discussed, and how to further enhance the technology to other projects and increase the operational envelope of the system.
Application of Sand Control Modeling Software in a Deepwater Multizone Frac Pack: A Case Study
Authors: Zhu Hong , Joseph Kevin , Chok Peter 
Published: June 2014

Abstract
This paper presents sand control software capabilities and modeling considerations for sand control operations. A case study that captures the planning and execution challenges of predicting work string behavior in a two-zone Frac Pack operation in a deepwater well in the Gulf of Mexico will be presented. The integrated sand control software was used to calculate a suitable set-down weight before the main treatment, taking into account the combined effects of ballooning, thermal gradients, buckling and piston effects unique to the single-trip multi-zone tool system deployed. The net weight at the packer as predicted by the modeling software was compared to downhole gauge data collected during the operation. A summary of lessons learned and future enhancements will be discussed as well.
Wettability Alteration with Brine Composition in High Temperature Carbonate Reservoirs
Authors: Chandrasekhar S. , Mohanty K. K. 
Published: June 2014

Abstract
The effect of brine ionic composition on oil recovery was studied for a limestone reservoir rock at a high temperature. Contact angle, imbibition, core flood and ion analysis were used to find the brines that improve oil recovery and the associated mechanisms. Contact angle experiments showed that modified seawater containing Mg2+ and SO42- and diluted seawater change aged oil-wet calcite plates to more water-wet conditions. Seawater with Ca2+, but without Mg2+ or SO42- was unsuccessful in changing calcite wettability. Modified seawater containing Mg2+ and SO42-, and diluted seawater spontaneously imbibe into the originally oil-wet limestone cores. Modified seawater containing extra SO42- and diluted seawater improve oil recovery from 40% OOIP (for formation brine waterflood) to about 80% OOIP in both secondary and tertiary modes. The residual oil saturation to modified brine injection is approximately 20%. Multi ion exchange and mineral dissolution are responsible for desorption of organic acid groups which lead to more water-wet conditions. Further research is needed for scale-up of these mechanisms from cores to reservoirs.
EOR in Tight Oil Reservoirs through Wettability Alteration
Authors: Kathel Prateek , Mohanty Kishore K. 
Published: June 2014

Abstract
In fractured reservoirs, the efficiency of water flood is governed by spontaneous imbibition of water into oil-containing matrix blocks. When the matrix is oil-wet or mixed-wet, little oil can be recovered by imbibition. The objective of this work is to identify chemicals that can be added to the injection water that can induce imbibition into an originally mixed-wet, tight, fractured sandstone reservoir. Several surfactants were evaluated for their aqueous stability at the reservoir temperature and salinity. Contact angles were measured on a clay-rich sandstone. Spontaneous imbibition tests were conducted on the reservoir rocks. It is shown that the use of dilute (0.1 wt %) surfactant solution can alter the wettability from oil-wet towards more water-wet condition on the mineral plates. Incremental oil recovery as high as 68% OOIP is obtained through spontaneous imbibition experiments performed on tight (∼10 µD) oil-wet/mixed-wet sandstone reservoir cores. Parametric studies performed using numerical simulation show that the rate of oil recovery increases with increasing wettability alteration, increasing fracture density, and decreasing oil viscosity.
Autonomous ICD Range 3B Single-Phase Testing
Authors: Least Brandon , Greci Stephen , Wileman Angel , Ufford Adam 
Published: June 2014

Abstract
Reservoir flow control is important for maximizing hydrocarbon production. Traditional in-flow control devices (ICDs) attempt to balance the completion pressure differential with the reservoir pressure differential so that even flow across production zones is maintained. This maximizes oil production by delaying unwanted fluids from breaking through. Unfortunately, when lower viscosity fluids do break through, they take over the well, significantly reducing production of the desired hydrocarbon. This paper describes the design and function of a self-adjusting in-flow control device referred to as an Autonomus Inflow Control Device (AICD). When hydrocarbons are producing from all zones, the AICD will behave as a traditional ICD, balancing flow. However, when low-viscosity (undesired) fluids break through, the AICD chokes them, significantly slowing flow from the zone producing the undesirable fluids. This autonomous function enables the well to continue producing the desired hydrocarbons for a longer time, maximizing total production.
The paper describes the laboratory testing performed to evaluate the performance of a new generation AICD design in field-like conditions. This new generation design is referred to as the Range 3B, and is similar to the original design now referred to as the Range 3A (Least et.al, 2012) in that it is the same size and shape, but it allows for increased flow rates while keeping similar performance ratios. Results from single-phase experimental flow testing with model fluids and crude oil are presented and discussed.
The testing results proved that the AICD could restrict flow from zones producing undesirable fluids. The discussion further shows that if technology such as the new AICD is applied to new well completion designs, total hydrocarbon recovery will be enhanced, providing a significant benefit for production companies and those involved in design and modeling of new well completions.
Hydrocarbon Saturation From Total Organic Carbon Logs Derived From Inelastic and Capture Nuclear Spectroscopy
Authors: Craddock Paul R. , Herron Susan L. , Badry Rob , Swager Lee I. , Grau James A. , Horkowitz John P. , Rose David 
Published: June 2014

Abstract
The accurate determination of formation hydrocarbon or water saturation is an essential step in the petrophysical evaluation of petroleum reservoirs. A novel method has been developed for estimating hydrocarbon saturation directly from a total organic carbon (Corg) log and a porosity log. The method is enabled by the recent development of a pulsed-neutron logging tool that combines inelastic and capture gamma ray spectroscopy measurements to provide a robust and accurate total organic carbon estimate. The method differs from the well-known approach of using carbon-to-oxygen ratios that is most often applied in cased-hole evaluation. The main advantages of this new method are that it does not require knowledge of formation water resistivity, it does not rely on a resistivity model, it does not require an extensive calibration database, and it is largely independent of clay or other lithology effects. Calculations are available to explore uncertainties in the saturation estimates arising from uncertainties in the log inputs. The statistical uncertainty in the estimate of hydrocarbon saturation is as good as 10 saturation units (s.u.) in conventional reservoirs with porosities of 15 p.u. or greater.
The method has been applied to the determination of hydrocarbon saturation in a variety of formations, including bitumen-filled dolomite, heavy oil sand, and shaly sands with both open-hole and cased-hole wells. The method works equally well in formations drilled and logged with either oil- or water-based mud. The saturation estimates have been benchmarked against a combination of conventional and new logging approaches (e.g., resistivity, magnetic resonance, and dielectric logs) and core measurements, with generally excellent agreement among independent determinations. Hydrocarbon saturations can be determined accurately using the method in a number of formation types where conventional methods and models for estimating fluid saturation commonly fail, such as freshwater and unknown water salinity in formations under enhanced oil recovery.
The case studies demonstrate that a Corg log derived from geochemical spectroscopy logs can be used to obtain reliable estimates of hydrocarbon saturation in a wide range of environmental conditions and formations.
Influence of Surface-Treated Nanoparticles on Displacement Patterns During CO2 Injection
Authors: Aminzadeh B. , Chung D. H. , Zhang X. , Bryant S. L. , Huh C. , DiCarlo D. A. 
Published: June 2014

Abstract
We propose a new strategy for carbon storage in which CO2 is injected into a geologic formation after emplacement of brine containing dispersed surface-modified nanoparticles. This strategy increases the sweep efficiency of CO2 storage in aquifers and enhances the aquifer storage security. The most likely mechanism is the generation of nanoparticle stabilized CO2/water foam which securely traps the injected CO2 for long periods of time.
As a consequence of low density and viscosity of CO2 at typical geologic storage conditions, CO2 injection into aquifers suffers from low sweep efficiency which manifests as the gravity override and viscous fingering. Here, we show that nanoparticles can reduce the mobility of the injected CO2 as it displaces brine, and therefore, increase the sweep efficiency. Further we show that displacing the injected CO2 with brine increases residual phase saturations, and therefore enhance the capillary trapping of CO2.
We conducted core flooding experiments in which liquid CO2 was used to displace brine with and without suspended nanoparticles. Sandstone cores with different degrees of heterogeneity were used to capture the effect of heterogeneity on the efficiency of the proposed technique. Saturation distributions and pressure drops were measured in real time with a modified medical CT scanner and pressure transducers. The use of nanoparticles is shown to render about 90% of the injected CO2 immobile and increases the sweep efficiency up to 20% when compared to the base brine case.
Extra-Deep Resistivity Experience in Brazil Geosteering Operations
Authors: Tilsley-Baker Richard , Antonov Yuriy , Martakov Sergey , Maurer Hans-Martin , Mosin Anton , Sviridov Mikhail , Klein Katharine Sandler , Iversen Marianne , Barbosa José Eustáquio , Carneiro Gabriel 
Published: June 2014

Abstract
The relatively recent development of azimuthal resistivity measurements enables proactive geosteering within complex reservoirs. These successful tools are the major contributor to the substantial expansion of horizontal drilling. The tools enable determining the distance (up to 5 m in ideal conditions) and the azimuthal direction to a resistivity boundary. In ideal conditions, the well is inside a high resistivity layer and the shoulder bed is low resistivity, giving geologists warning of approaching adjacent conductive beds. When the tool is in a low resistivity layer, the depth of detection of an adjacent high resistivity layer is much smaller. In these situations, it is often not possible to use the tool for effective geosteering.
An extra-deep resistivity tool has been used for several years in Norway and has been introduced in the Peregrino Field in Brazil. It operates at lower frequencies, has large transmitter-receiver spacings and a depth of detection up to 25 m. This tool was deployed in addition to the conventional directional resistivity instrument.
The new application in Brazil was supported by inversion software (still in development) to enable possible interpretation of the geology within the tool range. The inversion results provide information that can help identify adjacent reservoir layers while in the target zone and measure the thickness of the reservoir layer being drilled.
Examples are presented from one well where the extra-deep resistivity provided early warnings and additional information that helped to steer the well successfully and maximize reservoir coverage. The extra-deep measurements from the tool also provide valuable reservoir understanding and knowledge for future well planning purposes.
Managing Offshore Megaprojects: Success is an Option
Authors: Sterling Gordon H. 
Published: June 2014

Abstract
The success or failure of any offshore oil and gas development project is dependent on effective integration of intelligent processes, deep-seated technical expertise, multiple company and agency interactions and relationships, solid management and vigorous leadership. This is especially true for deepwater oil and gas developments where the costs are high, the schedules are critical, the technologies used are broad-based and deep, and there is heavy involvement of engaged stakeholders. Recent papers and books, with solid support in data and statistics, have shown that less than one-quarter of the international offshore oil and gas development projects have achieved "success" in any meaningful sense of that word. Furthermore, in a few cases, those that do are the beneficiaries of changed economic circumstances that override the real deficiencies. Based on many years of project experience, involving both success and failure, this paper deals with the many elements that create the environment where success is probable and failure is NOT inevitable.
Frequency Distributions of Effective Permeability and Gas Flux in Leaky Wellbores
Authors: Tao Qing , Bryant Steven L. , Checkai Dean A. 
Published: June 2014

Abstract
Using a previously described model, we estimate the effective permeabilities of about 300 wellbores in six different fields that exhibit sustained casing pressure (SCP) or surface casing vent flow (SCVF). Uncertain parameters that affect the estimated permeability, such as the location of the leak source, are accounted for by a Monte-Carlo simulation approach, yielding an expected value of leakage path permeability for each measurement of SCP or SCVF. Characterizing leakage paths can be useful in diagnosing and remediating poor zonal isolation. This can be particularly valuable in quantifying the likelihood that shallow groundwater is being contaminated by operations in deeper formations, such as shale gas production. Analogous leakage paths are a primary risk factor for large-scale geologic storage of anthropogenic CO2. Being able to estimate CO2 fluxes along existing wellbores is required for quantitative risk assessment.
The expected values of estimated permeabilities along most of the leaky wellbores are between 10 µd to 10 md. Using the wellbore permeabilities to estimate the aperture of the leakage pathways, we estimate the capillary pressure and hence the minimum CO2 plume heights required for CO2 to enter the leakage paths. Almost all leakage pathways require very modest plume heights, so capillary effects are unlikely to prevent leakage. We compute worst-case steady CO2 leakage fluxes, finding that over 90% of the fluxes are less than 0.1 ton/m2/yr. The frequency distribution of the effective permeabilities of leaky wellbores is believed to be the most comprehensive compiled to date. It enables quantitative assessment of leakage rates in a risk assessment context, in particular for the hazard of contamination of shallow resources (e.g. groundwater) by CO2 or natural gas.
Conditions for Generating Nanoparticle-Stabilized CO2 Foams in Fracture and Matrix Flow
Authors: Aroonsri Archawin , Worthen Andrew , Hariz Tarek , Johnston Keith , Huh Chun , Bryant Steven 
Published: June 2014

Abstract
Foams used for mobility control in CO2 flooding, and for more secure sequestration of anthropogenic CO2, can be stabilized with nanoparticles, instead of surfactants, bringing some important advantages. The solid nature of the nanoparticles in stabilized foams allows them to withstand the high-temperature reservoir conditions for extended periods of time. They also have more robust stability because of the large adsorption energy required to bring the nanoparticles to the bubble interface.
Silica nanoparticle-stabilized CO2-in-brine foams were generated by the co-injection of CO2 and aqueous nanoparticle dispersion through beadpacks, and through unfractured and fractured sandstone cores. Foam flow in rock matrix and fracture, both through Boise and Berea sandstones, was investigated. The apparent viscosity measured from foam flow in various porous media was also compared with that measured in a capillary tube, installed downstream of beadpacks and cores.
The domain of foam stability and the apparent foam viscosity in beadpacks was first investigated with focus on how the surface wettability of nanoparticles affects the foam generation. A variety of silica nanoparticles without any surface coating and with different coatings were tested, and the concept of hydrophilic/CO2-philic balance (HCB) was found to be very useful in designing surface coatings that provide foams with robust stability. Opaque, white CO2-in-water foams (bubble diameter &lt; 100 µm) were generated with either polyethyleneglycol-coated silica or methylsilyl-modified silica nanoparticles with CO2 densities between 0.2 and 0.9 g/cc. The synergistic interactions at the surface of nanoparticles (bare colloidal silica) and surfactant (caprylamidopropyl betaine) in generating stable CO2 foams were also investigated.
The common and distinct requirements to generate stable CO2 foams with 5-nm silica nanoparticles, in rock matrices and in fractures, were characterized by running foam generation experiments in Boise and Berea sandstone cores. The threshold shear rates for foam generation in matrix and in fracture, both in Boise and Berea sandstones, were characterized. The ability of nanoparticles to generate foams only above a threshold shear rate is advantageous, because high shear rates are associated with high permeability zones and fractures. Reducing CO2 mobility in these zones with foam diverts CO2 into lower permeability regions that still contain unswept oil.
Rate-Time Decline Analysis for Natural Gas Wells with Significant Rock Compressibility Effects
Authors: Zhang Miao , Ayala H. , Luis F. 
Published: June 2014

Abstract
State-of-the-art analysis of production performance of gas wells relies on material balance concepts combined with pseudo-pressure and pseudo-time for rate-time decline analysis and reserve estimations. Customarily, rock compressibility and reservoir pore volume change are either neglected or accounted for by replacing gas compressibility with total compressibility values. In this work, we extend the applicability of a rescaled exponential and density-based decline analysis approach (Ayala and Ye, 2012 and Ayala and Ye, 2013) for the decline analysis of gas systems experiencing significant rock compressibility effects. We formally derive the density-based analytical technique that rigorously captures formation compressibility effects during for the analysis of gas well production data during boundary-dominated-flow (BDF). This formulation enables calculation of correct prediction of well performance with depletion) by incorporating formation compressibility and the change of reservoir pore volume effects, which proves crucially important for high-pressure and/or large-formation-compressibility gas reservoir systems.
Modeling Gas Flow through Hydraulically-Fractured Shale-Gas Reservoirs Involving Molecular-to-Inertial Transport Regimes and Threshold-Pressure Gradient
Authors: Civan Faruk 
Published: June 2014

Abstract
This paper demonstrates that formulation beyond the usual is required for rigorous modeling of flow through hydraulically-fractured shale-gas reservoirs. This challenging task is demonstrated here by considering the transport of gas in nano-permeability shale-gas reservoirs, including absorption, adsorption, pore-confinement, and alteration of gas properties. This leads to significant deviations from the conventional treatment.