bluuebunny/crossref_metadata_2025_split huggingface dataset:
Experimental Coreflooding and Numerical Modeling of CO2 Injection With Gravity and Diffusion Effects
Authors: Moortgat Joachim , Firoozabadi Abbas , Li Zhidong , Espósito Rogério 
Published: February 2011

Abstract
In some high pressure and low temperature reservoirs the density of CO2 may be substantially higher than the oil density. Upon mixing of CO2 and oil, a gas phase with a high content of methane (C1) may also appear; when the C1 content is high, this gas phase may have a lower density than the oil. In relation to the above, we have conducted three comprehensive experiments studying CO2 injection from the top and bottom of a vertical core and injection in a horizontal core. The injection rate is i PV/day. The low rate which may correspond to field scale condtions allows the study of the effect of diffusion. The core diameter used in this work is 3.8 cm and the length is 27.3 cm. The tests are conducted at a pressure of 441 bar and temperature of 60°C. The coreflood results give a recovery of 98% for bottom injection, 84% for top injection, and 92% for horizontal injection. We have also conducted an extensive set of measurements to determine swelling, viscosity and density for the calibration of an equation of state. We simulate the experiments using a state-of-the-art higher-order finite element two-phase compositional model. The simulations show that Fickian diffusion should be taken into account, and that even in the horizontal injection there is a considerable gravity effect. One main conclusion is that there may be vast differences between CO2 injection in a 1D slim tube and in a core where there may be a 2D flow. A related conclusion is that analysis of CO2 core flooding at low injection rate may provide important insights into the process.
The Effect of Drillstring Rotation on Equivalent Circulation Density: Modeling and Analysis of Field Measurements
Authors: Ahmed Ramadan , Enfis Majed , Miftah-El-Kheir Hamza , Laget Morten , Saasen Arild 
Published: February 2011

Abstract
A number of field and laboratory studies have been carried out to accurately predict the effect of drillstring rotation on downhole pressure and equivalent circulating density (ECD). Field studies indicated that drillstring rotation often results in an increased ECD. This is in contradiction with the results obtained from number of laboratory studies and other field studies. Consequently, there is no comprehensive model that accounts for the effect drillstring rotation on wellbore hydraulics. Recently, simple empirical models have been developed based on field measurements alone. Although these models can be very useful as they are based on field measurements, they have no physical basis and are limited to specific ranges of field parameters.
This article presents results of field studies and theoretical analysis conducted on the effect of drillstring rotation on wellbore hydraulics. Field measurements during actual drilling operation were obtained from four different wells. Key drilling parameters such as flow rate, drillstring rotation speed, rate of penetration, ECD and return density, were recorded as a function of measured depth.
Selected published field measurements were analyzed systematically using dimensional analysis techniques. After correlating different dimensionless groups, a new semi-empirical model was developed. The model was rigorously tested for its accuracy. Model predictions were compared with new field measurements and predictions of an existing model. Model predictions show good agreement with field measurements. The new model exhibits appreciably better accuracy than the existing one.
The model developed in this investigation is relevant to manage ECD in slim holes, deepwater wells, and extended-reach wells where the increased wellbore length results in excessive pressure loss and limits the operating window for bottom hole pressure. In deepwater applications, ECD management becomes critical due to the narrow operating window between the pore and fracture pressure gradients.
Petrophysical Integration to Approach Tight Gas Sand Reservoir Characterization Problems in Cuervito Sur field, Mexico
Authors: Muñoz L. , Ochoa A. , Acosta M. , Brito F. 
Published: February 2011

Abstract
In the beginning of the field's exploitation, it was believed that where net gas thickness was greater, the associated production would also be greater. This assumption changed as time passed, as wells were found with similar net gas thicknesses but different production behavior. Available petrophysical studies at that time did not explain these differences, resulting in difficult reservoir analysis for the field.
To characterize the formation in a more precise manner, an integral petrophysical analysis was conducted, using all available information (core, production, geology and seismic). The analysis identified zones with high content of calcareous cement which affected the quality of the reservoir and its production potential. A multi-mineral petrophysics model that considers the existing lithologic factors and its influence in the rocks’ properties was used to locate the calcareous intervals, thus helping to reduce economic risk and investment of time in the development of the field.
To validate the methodology, results and predictions of this study, petrophysical fluid capacity assessments were compared with available production data in wells that had been previously expected to have similar production results, but in fact did not. The new fluid capacity analysis identified previously unrecognized differences in rock types within each well, further helping to explain the observed differences in production. The complete fluid capacity analysis better identified and explained production differences between existing wells and now helps to predict productive potential in new wells.
This study has demonstrated that petrophysics is a critical area for understanding the complexity of tight reservoirs. The classification of a reservoir as a function of its fluid capacity quality will allow for more efficient and successful planning of production intervals, impacting operational costs by avoiding stimulation of reservoirs without true potential.
Hybrid Rate-Decline Models for the Analysis of Production Performance in Unconventional Reservoirs
Authors: Ilk D. , Currie S. M. , Symmons D. , Rushing J. A. , Blasingame T. A. 
Published: February 2011

Abstract
Estimating reserves in unconventional gas reservoirs is problematic due to the longer transient flow periods exhibited throughout the production history. The common industry practice is to use the Arps empirical rate-decline relations (i.e., the exponential and hyperbolic decline relations), but these equations are only strictly applicable during boundary-dominated flow. Application of the Arps relations to transient flow often results in significant overestimation of reserves. Under these circumstances, there is an obvious need for a theoretically based rate-decline equation(s) that is applicable for all flow regimes.
We developed three main rate-time relations and five supplementary rate-time relations which utilize power-law, stretched exponential, hyperbolic, and exponential components to properly model the behavior of a given set of rate-time data. The new rate-time relations are developed based on the characteristic behavior of rate-time data in unconventional reservoirs. We also present the application of the βq,cp-derivative function for rate-time data diagnostics. Data diagnostics verify that stretched exponential function is sufficient to model rate-time behavior in unconventional reservoirs. Power-law, hyperbolic, and exponential components are incorporated into the proposed models to represent early and late time behavior. And therefore the new rate-time relations are called hybrid rate-time decline models.
We demonstrate that the new rate-time relations are well-suited for the estimation of ultimate recovery as well as for extrapolating production into the future. While our proposed models can be used for any system, we provide application almost exclusively for wells completed in unconventional reservoirs. As example applications, we present a variety of field examples using production data acquired from tight gas and shale gas reservoir systems.
CO2 Leakage from Heterogeneous Storage Formations
Authors: Saadatpoor Ehsan , Bryant Steven L. , Sepehrnoori Kamy 
Published: February 2011

Abstract
After injection of CO2 into the subsurface formation, various storage mechanisms help immobilize CO2 in the porous medium. Injection strategies that promote the buoyant movement of CO2 after injection can increase immobilization by the mechanisms of dissolution and residual phase trapping. In a heterogeneous storage formation where capillary entry pressure of the rock is correlated with other petrophysical properties, numerous local capillary barriers exist and can trap rising CO2 below them. In this work, we study the effect of these barriers on CO2 leakage from the storage formation. We first introduce a no-risk-of-leakage scenario for storage, which sets an upper bound on the amount of CO2 that can be stored without contacting the overlying seal. Accounting for capillary heterogeneity reduces this upper bound. In practice operators are likely to seek to store more CO2 than the no-risk-of-leakage bound in any given reservoir. Thus we also examine the form of the gas cap established by the rising CO2 plume, and we simulate leakage from this gas cap through the top seal. Our leakage scenario is simulated in different cases with homogeneous and heterogeneous capillary pressure field, and CO2 trapping is quantified based on the results of the leakage. Capillary heterogeneity is introduced via Leverett scaling group. A new parameter called security index is also defined to quantify the risk of leakage. Finally, the statistics of the local capillary barriers are used to find a probability distribution of leakage amounts from the storage formation.
We conclude that ignoring heterogeneity gives the worst case estimate of the risk. Local capillary trapping reduces potential leakage through failed seal, but a range of CO2 leakage amounts can occur depending on heterogeneity and location of leak. The thickness of the sealing layer and the presence of an active open aquifer connected to the leak do not change the leakage volume of CO2. A probabilistic approach based on statistics of local capillary barriers can be used to analyze the risk associated with leakage.
Management of Road Safety in Western Siberia
Authors: Flanagan Gerry , Bashara Yuriy 
Published: February 2011

Foreword
According to statistics, road accidents are perhaps the most frequent cause of death of external factors.
The global road fatality indicator is several times higher than the total number of fatalities caused by work-related injuries and industrial disasters.
Approximately one third of Exploration and Production operations fatalities are caused by road transport accidents. It is fundamental to ensure personnel safety of own, contractor staff and third parties involved in any EP land transportation. To maintain Company Safety reputation it is imperative to significantly improve land Transportation Safety Performance and reverse the deteriorating trend seen in 2006 & YTD 2007 towards ‘zero fatality’ in support of the NO HARM business principle.
This opportunity was identified as a way to address the road transport incidents in the July 2007 Shell EP Leadership Forum where SPD took very active participation and endorsed as one of four potential Sharper Focus Campaign work streams for Goal Zero in September, where safety was recognized as a fundamental, deeply-held value, just as we view honesty as part of our General Business Principles.
Salym Petroleum Development N.V. sets forth the task of ensuring road safety within the Salym project area. Goal - Zero Road Accidents.
Unique Combination Openhole / Cased Hole Solid Expandable Liner Facilitates Cost Effective Conversion of Producer to Gas Storage Well
Authors: Salute Claudio , Sardo Antonio , Marr Brian , York Patrick 
Published: February 2011

Abstract
Using the enabling technology of a solid expandable liner system allowed Edison–Milan to cost effectively convert a producing well in Italy to a gas storage monitoring well. The solid expandable liner allowed for the execution of two objectives in a one step operation; sealing off old production perforations and placing a mechanical barrier over a reactive shale formation in the openhole section immediately below the shoe of the previous casing string. The larger post expanded diameter of the combination openhole / cased-hole expandable liner also facilitated the eventual installation of larger diameter gravel pack (GP) screens.
This well required the isolation of old perforations in the toe of the casing as well as a need to cover an "active shale" section in the open hole. While the perforations could have been isolated by squeezing with cement and drilling out, the active shale would still cause a major problem when pumping the gravel pack. Being active means that when pumping fluids in the well, the shale could collapse or swell in on the completion equipment, causing installation problems.
Mitigating the old perforations and then fighting the active shale formations would cause non-productive time (NPT) and could have a large impact to the cost of the well. Additionally, the use of smaller gravel pack screens could impact the economic viability of the well.
The combination openhole / cased-hole solid expandable liner was run in order to isolate the perforations and blank off the active shale section in the open hole. The next hole section was drilled and a GP system was installed. The top of the GP packer was set above the solid expandable liner. The GP assembly and screen were run through the expandable liner into the target zone in the open hole.
The screen sizing is critical on gas storage, as the larger the screen the greater the production/injection rates that can be achieved. If a select screen has a base pipe that is too small, high erosion can occur across the screen wrap/weave, causing catastrophic results including total sand control failure. The solid expandable liner allowed a 4 in. diameter screen to be utilized rather than a 3-1/2 in. diameter screen.
First Polymer Injection In Deep Offshore Field Angola: Recent Advances on Dalia/Camelia Field Case
Authors: Morel Danielle , Vert Michel , Jouenne Stéphane , Gauchet Renaud , Bouger Yann 
Published: February 2011

Abstract
The Polymer Injection Project on the Dalia field, one of the main fields of Block 17 in deep offshore Angola, is a world first for both surface and subsurface aspects. In depth integrated geosciences and architecture study culminated, in January 2009, in the start of polymer injection in one of the Dalia water injection wells. Dalia field is a high permeability sandstone reservoir (&gt; 1 D on average) and contains a medium viscosity oil (1 to 11 cP under reservoir conditions).
The key challenges of the project were to start polymer injection:
– Very early in the field development since first oil was in Dec. 2006 – With much wider well spacing than in any other project, – Under high salinity conditions (&gt;25g/l) – With the specific logistics of a remote deep offshore area.
After a very positive single well injectivity test early in 2009, additional single well injectivity tests were performed end 2009 on three Dalia wells in various configurations. They demonstrated an injectivity of the polymer solution that satisfies the Field Development requirements in term of voidage replacement, as defined in the water injection base case.
During this testing period, the capacity of the logistics and surface facilities (capacity of 7 t/day) to successfully prepare the polymer solution on board the FPSO have been demonstrated after specific difficulties and issues were identified and fixed.
Based on these positive results, a Phase 1 project was sanctioned and started on 8th February 2010 on the Camelia complex. Viscosified water is injected in one of the four injection lines of Dalia field (average BSW of 20% on the associated producers at beginning of Phase 1 polymer injection). By mid June 2010, more than 3 MM bbls of cumulative of polymer solution have been injected in the Camelia reservoir.
The specificities of the Dalia field (large well spacing and low BSW at polymer injection start up) mean a late response if the usual EOR monitoring techniques are applied. Various monitoring options were considered to verify the injected polymer solution properties in-situ, and accelerate the sanction for a fullfield development. The studies concluded on a recommendation to drill a well to sample in-situ the injected viscosified water. Locations of the sampler well at a distance of 100m from an injector, and best timing to drill the well were based on 4D seismic data history match and waterflood performance forecast.
Increase of an Impeller Machine Efficiency by Proper Selection of a Blade with Minimal Aerodynamic Drag
Authors: Slobodkina Francheska , Malinin Vitaliy 
Published: February 2011

Abstract
This work deals with a problem of an impeller machine efficiency increase by proper selection of blade geometry. Impeller machines like fans, turbines, compressors, pumps etc. are the most commonly used devices in power, extractive, oil and gas and other branches of industry. It is well known that surface boundary layer formed on a blade surface is unstable that can results in separation, vortex structures formation and subsequent loss of a total pressure. All this phenomena decrease device efficiency and can cause emergency situations. In this work a mathematical model and corresponding numerical algorithm for fluid flow around a single blade or blade cascade are developed. This approach provides the possibility of blade profile optimization and device efficiency increase. Two fluid flow models are considered: Potential fluid flow around a blade or in blade cascade with subsequent boundary layer parameters and separation points exact location calculations (methods 1, 2).Numerical simulation of a blade profile or blade cascade based on solution of Navier-Stokes equations for viscous and turbulent flows (methods 3).
Solution strategy is based on sequential application of both mentioned above methods: starting from very fast potential flow calculation (few seconds are needed to obtain a results) and continuing with full set of Navier-Stokes equations simulation refining preliminary obtained results that can take dozens of hours. Such algorithm is especially important for problem of profile optimization while fast enough shift of a separation point in trailing edge direction is one of main goals. Subsequent profile improvement via solution of viscous fluid flow problem demands noticeably smaller time in comparison with direct profile optimization started from viscous Navier-Stokes equations simulation. Obtained results verification by available experimental data shows high efficiency of the proposed scheme. This approach applicability can be significantly expanded to areas where hydrodynamic processes accompanied by separation are of especial importance.
Minimizing Friction In Shallow Horizontal Wells
Authors: Mirhaj S.A. , Kaarstad E. , Aadnoy B.S. 
Published: February 2011

Abstract
Current knowledge allows us to drill the wells, using rotary drilling with drillcollars in the vertical part. The wells will be completed with screens that cannot be rotated during installation. Because a non-rotating mode leads to higher friction, it is questionable if we are able to land the entire horizontal screen due to lack of weight at this shallow depth.
Excessive surface weight may lead to buckling of the completion string. Simulations of the completion operations suggest that there is a high risk of stopping before reaching the target depth.
A study was undertaken on a shallow well with long horizontal section including side turns in this section to see how much friction is increasing due to these bends in the wellbore. This study is helpful for designing directional/horizontal wellbores in order to find the best well path profile that minimizes well friction as well as is a planned profile in acceptable from friction prospective. For this reason the friction profile during hoisting/lowering first the real 3-D well with side bens inside and then with keeping azimuth constant in the same well was performed and resulting friction profiles were comparing.
The study is based on a new 3-dimensional analytical friction model that was developed in 2009. It is simple and uses the dogleg (which includes both inclination and azimuth) and is therefore fully three-dimensional. The analytical model is applied with some modifications in order to capture the effect of weight in the horizontal section especially when BHA is dragging up/down into or out of the wellbore.
Drilling on Target with VSP Look-Ahead Technique in Deepwater India Exploratory Environment
Authors: Lim T.K. , Rana R. K. , Dutta R. K. , Sundaram K. M. 
Published: February 2011

Abstract
Frontier drilling in deepwater environments is challenging with a wide range of risks that oil operators need to evaluate carefully because of high-investment costs. The formation targets selected are typically depth transformed using a velocity function obtained from conventional 3D surface seismic data. The data are usually low resolution and may not have been processed with the best prestack depth migration (PSDM) techniques. This pitfall often leads to uncertainties in reaching drilling targets and completing the well on time. Common uncertainties faced by drillers are target confirmation ahead of an intermediate depth section and the distance to these targets. One approach to reduce this uncertainty is to use borehole seismic techniques to record a vertical seismic profile (VSP) at intermediate total depth (TD) to look ahead and estimate the target depths below the bit.
Oil and Natural Gas Corporation Limited (ONGC), India’s largest oil operator, has been using this simple, effective technique in drilling deepwater wells. In one case the look-ahead prediction resulted in stopping of drilling operations because ONGC needed to ascertain if there was reservoir rock below the volcanics. The unambiguous VSP result did not show any possible reservoir below 3987 m measured depth (MD), which saved 3.5 weeks of drilling to reach the predrilling planned TD of 4415 m MD. In another example, ONGC needed to complete a vertical well that extended to basaltic basement with TD planned at 4324 m at a subsea water depth of 2135 m. Three look-ahead VSP runs were performed at various sections for guidance throughout the drilling process, setting the casing, and reaching the deeper final target. Final TD was 6205 m MD as opposed to the planned TD of 4324 m MD.
While VSP techniques have been widely used by the exploration communities particularly the geologists and geophysicists, they are also a look-ahead tool applicable for drilling operations planning and ahead-of-bit drilling risk mitigation.