bluuebunny/crossref_metadata_2025 huggingface dataset:
Core Tests for Relative Permeability of Unconventional Gas Reservoirs
Authors: Dacy John M.
Published: February 2011

A combination of up to seven or more core tests provides a practical approach to krg and krw function definition even when absolute permeability is at the sub-microdarcy level. The method is designed to provide data needed to define function parameters required by traditional engineering equations for relative permeability. This is accomplished with cores by determining end point specific permeabilities, end point non-wetting phase trapping capacity, critical gas saturation, and a small but sufficient number of effective gas permeabilities to define both drainage and imbibition krg as functions of water saturation. Assessment of the krw function is handled variously and is described. This combination-method is used because traditional core tests involving somewhat continuous displacement are invalid or not practical when cores have absolute permeability approaching a microdarcy and lower.

Conventional analysis of gas shale and tight gas sand cores provides a snap-shot of reservoir permeability. The more complete view of flow capacity needed by engineers and petrophysicists comes with the availability of gas-water relative permeability. Measured relative permeability data are used for reservoir simulation, production forecasting, interpretation of formation damage, and to develop detailed reservoir permeability versus depth profiles.

Sample and test conditions are described. Data for several tight gas sand and gas shale cores are presented along with the required data integration steps to combine the separate test results and to generate relative permeability functions of water saturation. Results show these unconventional rocks can be characterized with well-known relative permeability equations and that traditional rock-property logic can be followed during data integration.

The significance of this work lies in presentation of a novel yet practical solution for acquiring rock curves from unconventional rocks. It is believed to represent the first treatment of core tests for krg hysteresis in tight gas sands and of core-based development of relative permeability functions in gas shales.
Scaleup Methodology for Chemical Flooding
Authors: Veedu Faiz Koyassan , Delshad Mojdeh , Pope Gary A.
Published: February 2011

Accurate simulation of chemical flooding requires a detailed understanding of numerous complex mechanisms and model parameters where grid size has a substantial impact upon results. In this paper we show the effect of grid size on parameters such as phase behavior, interfacial tension, surfactant dilution and salinity gradient for chemical flooding of a very heterogeneous oil reservoir. The effective propagation of the surfactant slug in the reservoir is of paramount importance and the salinity gradient is a key factor in ensuring the process effectiveness. The larger the gridblock size, the greater the surfactant dilution, which in turn erroneously reduces the effectiveness of the process indicated with low simulated oil recoveries. We show that the salinity gradient is not adequately captured by coarse grid simulations of heterogeneous reservoirs and this leads to performance predictions with lower recovery compared to fine grid simulations. Due to the highly coupled, nonlinear interactions of the many chemical and physical processes involved in chemical flooding, it is better to use fine-grid simulations rather than coarse grids with upscaled physical properties whenever feasible. However, the upscaling methodology for chemical flooding presented in this paper accounts approximately for some of the more important effects, as demonstrated by comparison of fine grid and coarse grid results and is very different than the way other enhanced oil recovery methods are upscaled. This is a step towards making better performance predictions of chemical flooding for large field projects where it is not currently feasible to perform the large number of simulations required to properly consider different designs, optimization, risk and uncertainty using fine-grid simulations.
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

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

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

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

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

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

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

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 (> 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 (>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

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

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

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.
Shallow Azimuthal Measurements A Step Towards 3D Petrophysical Evaluation in Thin Reservoirs
Authors: Daghar Khadija Ahmed , Sayed Raza Hassan , Abdelaal Atef Farouk
Published: February 2011

Petrophysical evaluation in horizontal wells using standard logging while drilling (LWD) data is challenging, especially in thin reservoirs (~ 4 ft) bounded by dense resistive formation. These challenges are predominately associated with the propagation deeper depth of investigation (DOI) resistivity measurements and limitation in recording azimuthal data around the borehole.

In thin reservoirs the currently used electromagnetic (EM) resistivity tools with deeper DOI are usually affected by proximal beds which results in inaccurate saturation estimation for the target zone. Add to that, the traditional way of computing saturation using average porosity and resistivity measurements neglecting the variation around the borehole; this may result over/underestimating the water saturation which is an important factor in the STOOIP calculation.

This paper will discuss a "3D Petrophysical" approach utilizing a new technology that provides shallow azimuthal resistivity measurements around the borehole. The approach is used in integration with the available methodology of utilizing azimuthal density data to capture the variation in water saturation (Sw) around the borehole in thin heterogeneous carbonate reservoirs.
The Effects of Low-Permeability Mudcake on Time-Dependent Wellbore Failure Analyses
Authors: Tran Minh H. , Abousleiman Younane N. , Nguyen Vinh X.
Published: February 2011

The effects of filter cake buildup and filter cake properties variation with time on the wellbore stresses and wellbore stability have been plaguing the industry for long. The increasing use of lost circulation materials (LCM) in recent years for wellbore strengthening in weak and/or depleted formations nessesitates real-time models that can predict these effects. However, the complexities of effective stresses and pore pressure real-time evolution, i.e. while drilling, coupled with the time-dependent properties of mud filtration have delayed such modeling attempts. In this paper, the analytical solutions for the time-dependent coupled effects of mudcake buildup on the wellbore stresses and formation pore pressures controlling wellbore collapse and fracturing are derived. The transient effects of mudcake buildup, mudcake permeabilities, and mudcake buildup coupled with its permeability reduction during filtration on the safe drilling mud window were illustrated through numerical examples. The results showed that the safe mud weight windows are greatly affected by the buildup of filter cake and its permeability variation. In particular, the analysis for the mudcake with permeability of 10-2 mD showed a widening of safe mud weight window by 0.9 g/cc after 2.5 hrs post excavation compared to that of a wellbore without mudcake. On the other hand, analysis with a 10-3 mD mudcake showed a widenining of mud weight window by as much as 1 g/cc. In addition, analyses revealed that even for mudcake permeability as low as 10-3 mD neglecting the permeable nature of the mudcake results in overestimation of the safe drilling mud weight window.
Gyro-While-Drilling Technology–Solution for Directional Tophole Drilling
Authors: Kasumov Ruslan , Houvet Joris , Kasumov Timur
Published: February 2011

A new borehole surveying technology, gyro while drilling (GWD), provided benefits for Sakhalin Energy Investment Company Ltd. (Sakhalin Energy) when used on two multiwell offshore platforms with only 2.5 to 3 m spacing between well slots. Such narrow slot spacing makes it impossible to get good MWD surveys while drilling top hole because nearby casing magnetic interference results in extremely high collision risk. Conventionally, this risk is mitigated by using wireline single-shot gyro and drop gyro, but both of these methods have drawbacks, such as extra personnel involved in wireline operations, additional rig time, and higher risk of stuck pipe. GWD was used to survey 30-in. conductors, already driven in place at the start of the campaign, and to survey 17.5- to 24-in. tophole sections. To date, 15 top holes have been successfully drilled and surveyed with this technology, with significant savings in rig time and reduced personnel on board (POB) due to the lower number of personnel needed in comparison with conventional wireline gyro surveys.

This paper intends to raise the awareness of the oil and gas industry about the new GWD borehole surveying technology, which has been proven to be reliable and which requires much less rig time and fewer POB for the job.

The overall results after 15 top holes drilled are: 12.6 rig days saved due to reduction of surveying time, reduced HSE exposure by eliminating wireline operations, improved platform POB while drilling top holes, and increased precision of the BHA steering by bringing the direction and inclination (D&I) package closer to the bit.

In this project, GWD technology has proven its ability to reduce rig time while providing close-to-the-bit and accurate D&I measurements, which is essential for drilling directional top holes in offshore environments. A full field data analysis details the significant rig time reduction and reduced POB when using GWD technology versus conventional wireline single shot and drop gyros.

GWD technology can be applied as a solution to any offshore project where using gyro surveys is inevitable because of a crowded well setting that makes the use of conventional MWD tools impossible.
Undersaturated Tagai Oil Reservoir Evaluation And Development, West Siberia, Russia
Authors: Parnachev Sergei , Molodykh Pavel , Mezentsev Dmitriy , Anop Alexander
Published: February 2011

Example of integrated study including adapted laboratory research program and reservoir engineering is provided. Results received are to be of interest of reservoir engineers and geologists especially in view of numerous low permeable oil fields’ production in low-amplitude closures. Combination of independent analysis techniques allowed detecting undersaturated type of Tagai reservoir. Oil displacement efficieny test was realized under specified oil saturation similar to log interpretation results. Resulted displacement efficieny values allowed previous oil recovery factor reduction as well as recoverable reserves by 30 percent, the latest were approved by State Authorities in 2009. Description of saturation estimation technique with undersaturated reservoir laboratory model formation is provided in the paper as well as laboratory research program. Advanced field development experience and iterative laboratory research program resulted in atypical level of interaction between laboratory and engineering departments based on complex geology understanding and modern reservoir engineering methods. Especial importance of implemented laboratory research consists in conception of undersaturated reservoir estimation, modeling and field development planning because of their quantity and distribution underevaluation at least at West Siberia.
Artificial Lift Practice for Heavy Oil Production with Sand Control
Authors: Petrov Alexander , Mikhaylov Alexander , Litvinenko Konstantin , Ramazanov Rustem
Published: February 2011

The goal of present study was to develop and test a new algorithm to selection proper artificial lift method for heavy oil production with sand control. We developed a Matrix of technologies for such oilfields using operating experience worldwide. For selected methods we defined production characteristics using Technology Application Template - a special tool which determines the most profitable artificial lift system based on net present value criteria. Solutions were implemented in North Komsomolskoe field located in Western Siberian basin.

Before performing calculations we defined the following: ■Oilfield characteristics■Well parameters■Limitations of artificial lift methods■Operational expenses for each artificial lift method

Recommended methods were tested on vertical wells of North-Komsomolskoe oilfield pilot area and on remote horizontal well in the north part of the field. The highest rate was reached using progressing cavity pump on horizontal well. On vertical wells of pilot low productivity area gaslift and hydraulic jet pump (which are economicaly efficient) have been successfully tested.

This paper describes combined analytical and operational approach for complicate field development.
Real-Time Bit Wear Optimization Using the Intelligent Drilling Advisory System
Authors: Rashidi B. , Hareland G. , Tahmeen M. , Anisimov M. , Abdorazakov S.
Published: February 2011

Real-time tools and techniques have recently been used in drilling operations to minimize time and cost, thus improving drilling performance. The real-time drilling data transmission and analysis, from a remote server to an office location, plays an important role in the drilling optimization process. The drilling engineers can provide their expert opinions to the rig personnel, thus increasing drilling efficiency as well as reducing the associated risks. It has been shown that associated drill bit problems can greatly affect total drilling efficiency. Among them, bit wear while the bit is still in the hole can highly influence the operation if it is not properly analyzed. This paper describes the real-time application of a developed model for bit wear analysis. The model was developed based on the differences between rock energy models, Mechanical Specific Energy (MSE), and rock drillability from rate of penetration models. It has been modified and implemented as an engineering module in the newly developed software, Intelligent Drilling Advisory system (IDA's), and is used to estimate real-time bit wear for both rollercone and PDC bits. The drilling data is retrieved by the software from a remote server for the analysis. The data is subsequently quality controlled before calculating instantaneous bit wear while the bit is in the hole. In this study, bit runs for two offset wells in Alberta, Canada, will be analyzed in detail using the software module. Similarities between the recorded bit wear outs reported in the field and the simulation results indicate that the procedure can be used for bit wear estimation with good accuracy. This engineering software module could be used to identify unnecessary tripping which will result in time and cost reductions as well as an additional tool to aid in estimating bit wear status while drilling.
Soft Multiphase Flow Metering for Accurate Production Allocation
Authors: Lorentzen Rolf J. , Nævdal Geir
Published: February 2011

Distributed temperature sensing (DTS) based on fiber-optics has successfully been applied for injection monitoring, see e.g. [1, 2], as well as production monitoring, see e.g. [3]. In the current paper we combine a transient well flow model and the ensemble Kalman filter into a tool for interpretation of high frequency downhole temperature measurements. Our case study clearly demonstrates the feasibility of automatic identification of reservoir influx distribution from temperature measurements.
Using Hydrajet Perforating Technique as an Effective Alternative to Explosive Perforating for Algerian Oil and Gas Fields
Authors: Kritsanaphak Kritsana , Tirichine Salah , Lamine Abed Mohamed
Published: February 2011

Hydrajet perforating (HJP) has been used in the oil industry for several decades to perforate or slot through casing by high-pressure abrasive jetting, which generally is not cost effective compared to conventional explosive (shaped-charge) perforating. However, within the Algerian oil fields, perforating using explosives has become time consuming and costly because of the strict security requirements associated with explosives. Operators commonly encounter delays in getting the explosives, varying from one week to one month, causing loss of production time and added standby costs for the rig and associated service equipment. Therefore, a nonexplosive solution like HJP has great value as an alternative to explosive perforating.

HJP, which forces highly pressured abrasives through jets to impinge/penetrate casing, cement, and formation, can be deployed on coiled tubing (CT) or jointed pipe. Typical penetration depths of 5 to 8 in. can be achieved, depending on the formation characteristics, tool configurations, pressure differential through the jet, and stand-off of the tool inside the casing. Perforation diameters from 0.75 to 3 in. have been achieved, as indicated by field tests and image logs run after perforating. This process has been developed and optimized for various applications, such as perforating for production, remedial cementing, or for hydraulic fracturing. It also has often shown advantages over explosive perforating, not only on a technical level but also from an economic perspective.

Therefore, hydrajet perforating is a valuable alternative to explosive-perforating techniques and does not require special authorizations for transportation and handling. This technique has benefited several operators in Algeria, saving cost and time, and also providing other advantages. This paper presents various applications of this technique and how it became an effective alternative to explosive perforating in several case histories from Algeria.
Casing While Drilling (CwD); A New Approach Drilling FIQA Formation in the Sultanate of Oman. A Success Story
Authors: Sánchez F. , Turki M. , Nabhani Y. , Cruz M. , Houqani S.
Published: February 2011

The highly reactive FIQA shale used to compel well engineers in The Sultanate of Oman to plan the drilling phase of surface and intermediate sections based on time exposure to aqueous drilling fluid system (WBM). The new approach of drilling the time-dependent FIQA shale formation using Casing-while-Drilling (CwD) allows well engineers to plan prospect top/intermediate wellbore sections differently by enhancing the drilling performance and reducing the risk of setting casing strings shallower, external corrosion due to aquifers, and getting stuck or reaming continuosly while drilling conventionally. The technical feasibility study, planning, risk assessment, execution, as well as the lessons learned during the process of drilling top sections are described in this document. The CwD team compares the drilling performance of several offset wells and suggest actions to improve the CwD technology in Oman.

Two surface sections were drilled successfully with large OD casing strings. Both surface sections 17½" and 22" reached 750m and 894m measured depth, respectively, reducing drilling phase by 40–45% in comparison with the average in the field. The exposure time of FIQA to aqueous environment was reduced considerably eliminating conditioning trips and non-productive-time (NPT) associated with wellbore instability. The volume of returns as cementing increased from 20% - with conventional drillstring - to 92–98% of pumped excess volume. CwD will allow drilling teams to slim down top holes by drilling/casing much deeper sections within less time preventing FIQA from collapsing and avoiding potential applications of Oil Based Mud (OBM). This new technology may also allow the optimization of existing rigs reducing cost and size of rig prints, as well as minimize HSE risk while handling large-OD casing and extremely heavy DC’s.

Simulation of the drilling phase using torque/drag and BHA-analysis software were run. The drillable PDC bit performance is compared to bit-records from offset wells recently drilled with conventional BHA’s. The effect of CwD on resulting uniform cement sheath (related to the "smear effect") and the reduced size of cuttings at surface which positively aid on preventing flow-line plugging as an unplanned event will be described.

It is important to highlight that Nonretrievable 17½"×13⅜ and 22"×18⅝ CwD with drillable bit and the casing drive mechanism, did not require any rig modification. The optimization of the process as well as the familiarization of drilling teams with the main components of the CwD system, will lead to a long, demanding scope for its implementation in several fields in Oman.
Optimizing Methods of Profitability Assessment and Well Cluster Drilling Rating with Account of Capital Expenditures
Authors: Atnagulov A. R. , Ismagilov R. R. , Nekipelov Y. V. , Kireev G. A.
Published: February 2011

When assessing economic feasibility using the NPV indicator, of some importance is the order of commissioning well clusters – the earlier a prospective well cluster is commissioned, the higher the NPV. This being said, creation of an optimal well commissioning schedule is directly conducive to maximizing the project's total efficiency. Traditionally, Rosneft uses a ‘geological’ drilling rating system when making up well cluster drilling schedules; this approach is based on initial production rates. This system ignores capital expenditures, the bulk of which goes to well drilling and the associated surface construction; but quite often well clusters with high initial production rates prove less profitable owing to outweighing capital costs.

With the purpose of increase NPV of the project, it is proposed to exercise drilling of well clusters according to their economic efficiency. The initial step in field development is constructing the basic common objects. For a quick payback, it is necessary to first commission well clusters having the greatest economic efficiency. The calculation of the technical/economic rating is performed iteratively in several steps, each of which picks up a well cluster with the maximum NPV. The amount of surface facilities for each well cluster remains variable across the iterations. This approach is implemented in the company's proprietary software package.
Viscosity Influences of High Pressure on Borate Crosslinked Gels
Authors: England K.W.. W. , Parris M.D.. D.
Published: February 2011

Fracturing fluid formulations, testing methodology and equipment has evolved, as have industry-accepted standards for testing. These standards have undergone a number of revisions over the years, and were published first as a recommended practice under the American Petroleum Institute (API-RP39) and subsequently under the International Standards Organization as ISO-13503-1. These standards define the geometry, shear rate, temperature control and other test parameters to measure the fluid performance under in-situ reservoir conditions. Little focus was given to the pressure applied to the fluid, other to ensure that it would not be allowed to boil under the test conditions. This lack of emphasis on pressure is completely understandable, as condensed matter (solids and liquids) typically have a limited response to the pressures experienced in the wellbore or during fracturing operations. And a typical expectation for compressible fluids, oils for example, is to experience an increase in viscosity with increased pressure.

It has been found that pressures (hydrostatic and pressure applied during pumping operations) encountered during hydraulic fracturing can materially reduce the viscosity of a borate crosslinked fluid. The loss in viscosity, depending on fluid formulation, temperature and pressure, can range from negligible to catastrophic. This phenomenon has been studied using high pressure rheometry and high pressure nuclear magnetic resonance (NMR), and has only recently been published in the scientific literature.

This paper will present results from testing a variety of fracturing fluids, including polymeric and viscoelastic surfactant-based, under in-situ conditions. It will detail the results of these tests for borate crosslinked fracturing fluids, and analogues not employed in the industry.

Based on these data, it will be clear that fracture geometry and proppant placement will be influenced. This is particularly true for deepwater treatments where the in-situ pressures are very high.