bluuebunny/crossref_metadata_2025_split huggingface dataset:
Water Saturation in Tight Gas Reservoirs
Authors: Crotti M. A. 
Published: December 2007

Abstract
Assuming a non-equilibrium scenario most of the non-conventional properties of gas-tight reservoirs are fully explained.
The model is able to describe, among others, the following typical characteristics of these reservoirs: over-pressurization, "abnormal" low water saturation, unusually small or undetectable capillary transition zones, abnormal pressure gradients, reservoir to reservoir disconnection and absence of identifiable free water level.
After accepting de usual over-pressurization as a direct indication of absence of hydrostatic equilibrium, the usual upscaling of capillary pressure curves results meaningless. It is so because capillary pressure was not originated in hydrostatic columns but in over-pressurization occurred when hydrocarbons were expulsed from the source rock (usually in close contact with reservoir rock).
As a result, fluids distribution is affected by non-hydrostatic equilibrium conditions still acting at the time of reservoir discovery.
A specially designed laboratory routine to measure the water saturation and electric properties directly on cores avoiding the usual water column modeling through capillary pressure curves, is presented. The relative permeability curves validity is also discussed.
Upscaling the Girassol Field: Comparative Tests and Impact of Near-Well Upscaling
Authors: Ding D. Y. , Artus V. , Roggero F. , Berthet P. H. 
Published: December 2007

Abstract
Girassol is a large and complex turbidite and highly faulted field. 3D high resolution seismic was shot, which gives good geological description and high level definition of heterogeneity. High quality seismic data allows constructing detailed stratigraphic model containing several tens of millions of gridblocks, which cannot be directly used for flow simulation. Reservoir properties must be upscaled on coarsen grid in dynamic flow simulation.
This paper discusses the upscaling techniques appropriate for turbidite and highly faulted field such as Girassol field. Upscaling of absolute permeability and geological facies are particularly addressed. Near-well upscaling technique is illustrated.
Modelling and Early Monitoring of Miscible Gas Injection in the Tight El Gassi Field, Algeria
Authors: Hadidi Boumediene , Ovens Jonathan 
Published: December 2007

Abstract
The El Gassi field is a Cambrian age sandstone oil field, located in central Algeria. The field lies approximately 100km south of the giant Hassi Messaoud field and shares many characteristics with its larger cousin. Production from El Gassi began in 1959 and has continued in depletion mode up to 2004. In 2000 a joint venture between Amerada Hess and Sonatrach, SonaHess, took over operatorship of the field. Because of the low permeability and adverse mineralogy for water injection, secondary miscible hydrocarbon gas injection was planned in El Gassi. Early gas injection (EGI) began in 2004 and an extensive data collection program has been conducted.
Between 2001 and 2004, an extensive integrated reservoir study was undertaken, with a view to predicting the likely increase in reserves from miscible gas injection. The study integrated Geophysics, Geology, Petrophysics, Production and Reservoir Engineering and lead to the development of a detailed Full Field simulation model.
This paper presents the main findings from the integrated study, with emphasis on the development and predictions arising from the resulting reservoir simulation model. Results from the ongoing monitoring of EGI indicates a positive response to gas injection. Field data are also presented and compared to the simulation results.
Heavy Oil Recovery by Liquid CO2/Water Injection
Authors: Al-Quraini A. , Sohrabi M. , Jamiolahmady M. 
Published: December 2007

Abstract
Alaska's North Slope reservoirs contain a massive heavy oil resource. There has been some success producing the less viscous crudes in the West Sak formation by waterflooding and water-alternating-gas injection. CO2 injection could also have potential applications as an enhanced oil recovery (EOR) process with the added benefit of providing a solution to the problem of produced CO2 present in the associated gas. CO2 is generally in supercritical state in normal reservoir conditions. However, permafrost causes an unusually low reservoir temperature and as a result CO2 will be in liquid state for these heavy oil fields.
In this study we consider West Sak reservoir and investigate different injection strategies in which available water and CO2 can be utilized individually or combined for EOR and CO2 storage purposes. A three-phase, threedimensional, black oil simulator was constructed accounting for the oil swelling and viscosity reduction due to dissolution of liquid CO2.
The results indicate that a combination of water and CO2 injection could be an attractive recovery method from the West Sak with higher oil recovery obtained when CO2 and water injection carried out early in the production life of the reservoir. If depletion precedes CO2 injection, CO2 storage is at its maximum. The recovery under liquid CO2 injection was almost the same as that of water flood due to its reduced mobility compared to CO2 gas. Water-Alternating-CO2 injection and Simultaneous-Water-CO2 injection showed significant improvement compared to water or CO2 injection alone. At Water-Alternating-CO2 (volumetric) ratio less than one, lower CO2 is required and higher CO2 storage per standard barrel of produced oil is obtained if CO2 is injected at higher rate for shorter period. Whist at Water-Alternating-CO2 ratio greater than one, reducing duration of CO2 injection favoured oil recovery but lowered CO2 retention factor compared to lowering CO2 injection rate.
Controls on Water Cresting in High-Productivity Horizontal Gas Wells
Authors: Sech R. P. , Jackson M. D. , Hampson Gary 
Published: December 2007

Abstract
It is widely agreed that gas reservoirs with a component of water drive should be produced at high rates to minimize the volume of gas which is trapped at high pressure by the advancing water (often termed ‘outrunning the aquifer’). Yet high production rates are also associated with coning (in vertical wells) or cresting (in horizontal wells) of the encroaching water, leading to early water breakthrough. In vertical wells, the formation of an inverse gas cone means that high gas rates can be maintained post-breakthrough until almost the whole perforated interval is flowing water. However, in horizontal wells, water breakthrough is a serious threat to gas deliverability, because the inverse coning mechanism does not apply and the well rapidly loads with water. Consequently, it is not clear whether producing at high rates is the best strategy to maximize recovery in gas reservoirs developed using horizontal wells.
We investigate the risk associated with producing horizontal wells at high rates by simulating gas recovery and aquifer response over a broad range of reservoir properties and production scenarios. We find that high rates always result in lower gas recovery unless the ratio of vertical to horizontal permeability is very low, in which case water cresting is suppressed. However, there are many instances where accelerating production recovers only slightly less gas over much shorter timescales, so may be economically favorable. Rate sensitivity increases in low permeability reservoirs with thin gas columns, because these conditions increase the tendency for water cresting, and decreases in reservoirs with strong aquifer support, since water breakthrough occurs regardless of the rate at which the well is produced. Our results can be used as a reference framework to rapidly assess gas production behavior and aquifer response within a wide range of field development scenarios.
Data-Driven Interpretation of Array Logs in Vertical and Deviated Wells
Authors: Frenkel Michael A. 
Published: December 2007

Abstract
We present a new method that is designed for accurate formation resistivity Rt estimation using inversion of galvanic or induction array logs acquired in vertical and deviated wells. At the first step, the method generates a near-borehole resistivity structure of a fixed thickness using inversion of the shallow-reading log measurements. At this step, the method does not aim for accurate estimation of Rxo but determines the parameters of an equivalent near-borehole zone that enables explaining (or fitting) only the shallow measurements. At the second step, the method determines the virgin zone resistivity, Rt, using inversion of the deep-reading logs in the model, which includes an equivalent near-borehole zone determined at the previous step. Because at each step the method performs inversion for a single model parameter, it enables fast and stable reconstruction of the Rt. To illustrate how the method can be used in practice, we present two field examples using array induction (2D case) and array lateral log (3D case) data.
Openhole Horizontal Gravel Packing Offshore Brazil: Best Practices and Lessons Learned From 72 Operations
Authors: Farias R. , Li J. , Vilela A. , Aboud R. 
Published: December 2007

Abstract
The challenge of the alpha/beta waves gravel packing open hole in offshore Brazil is how to successfully displace the proppant slurry in a large wellbore with a low fracture gradient formation, deep to ultra-deep water depths, and extended reach horizontal section.
Since 2001, job data from more than 72 open hole horizontal gravel packings have been compiled into a database. This paper reviews the well information and the key gravel packing parameters: pump rate, fluid density, injection proppant concentration, inner/outer annulus area ratio, dune ratio, packing rate, packing time and packing efficiency during alpha/beta waves. The engineering implementations and challenges, the best practices and lessons learned for open hole horizontal gravel packing are also summarized. The data analysis yields a better understanding about the open hole horizontal gravel packing in the Brazil offshore and provides a good guideline for future practice. A historical review is also presented showing how the gravel packing methodology has improved packing efficiency and success rate.
Case histories are provided demonstrating how to deploy the single trip system and pack the extended reach wellbore utilizing ultra-light-weight (ULW) proppant under extreme with improved packing efficiency and the success rate.
Porosity With Nuclear Magnetic Resonance in Naturally Fractured Clastics Reservoirs in the Devonian of the Bolivian Sub-Andean
Authors: Aguirre Omar , Glorioso Juan Carlos , Morales Jeannette , Mengual Jean François 
Published: December 2007

Abstract
We have validated with superior results that the direct measurement of porosity using Nuclear Magnetic Resonance (NMR), in Naturally Fractured Clastics Reservoirs of very low porosity (≍ 3.5%) in the Devonian of the Bolivian Sub-Andean, reveals information till now incoherent compared with core data. As it is well known, when the rock does not have paramagnetic elements, the porosity measured with the NMR is not affected by the minerals within the matrix and the tool answers mainly to the contained fluids in the pores of the rock. This peculiar characteristic of the NMR response in these low porosity reservoirs, with complex and variable lithology, become fundamentally beneficial at the time of determining an immediate porosity value with less uncertainty in comparison to the one from conventional logging tools, such as the Neutron, the Density and the Sonic, where there is a need to assume variable values of density and transit time for the matrix.
To corroborate that the obtained effective NMR porosity, is the best to be easily and truthfully correlated to true formation porosity, core data information are available. The key to obtain a reliable and precise measurement of porosity through NMR in these complex environments is based on the optimum selection of the acquisition parameters for the tool, like the polarization time, the echo-spacing and the use of a fit-for-purpose T2 cutoff time, tailored for this type of reservoirs. Furthermore, it will be demonstrated that the effects of nuclear diffusion on the transversal relaxation time distribution (T2 mode), primarily caused by gas, are not significant in these reservoirs, since an underestimate of the porosity was not noticed with regard to the one from cores.
Additionally with the aim of obtaining a better correlation among cores and NMR porosities, it has been used a specific high resolution acquisition and processing method, achieving continuous porosity measurements with a dynamic vertical resolution of 22 inches, more suitable to the sampling core interval and to the real petrophysical characteristics of our fields.
Realistic History Matching of Cyclic Steam Stimulation Performance of Several Groups of Multilateral Wells in the Peace River Field, Canada
Authors: Koci Paul Frantisek , Mohiddin Junaid Ghulam 
Published: December 2007

AbstractWith 8 billion barrels of bitumen in place and more than 30 years of thermal piloting and demonstration projects, Peace River offers an excellent growth opportunity for Shell's ultraheavy oil portfolio. In support of this initiative, integrated geological and reservoir modeling of two project areas was conducted. The key objectives were toimprove predictive modeling capability of cyclic steam stimulation (CSS) projects by history matching two groups of CSS multilateral wells and develop a history matched physical representation that not only validates empirical models but can be deployed to optimize CSS designs for full field development.Detailed geological models were created over two pad areas providing a geological framework large enough to have realistic boundary conditions, including impact of surrounding wells. The geological models were imported into CMG's STARS thermal reservoir simulator, and a relatively fine grid was extended over each project area. All available historical production, injection, pressure and temperature data were used in history matching. Steam-induced reservoir dilation, explicit fracturing, and relative permeability hysteresis were important aspects of the overall physical representation. Common physical parameters for dilation/re-compaction, fractures, permeability/porosity transforms, vertical to horizontal permeability ratios, and relative permeability hysteresis were used for both pads. Each pad area maintained its own unique geological, petrophysical, and fluid properties, in line with observed field trends. Excellent history matches (aided by experimental design) of injection and production volumes, injection wellhead pressures, estimated production bottom-hole pressures and temperature profiles were achieved not only for the entire Pad A and B groups of wells, but also for the individual wells.In summary, a predictive CSS simulation model has been developed and validated by history matching two areas of the Peace River field. The model is suitable for sensitivity studies of geological, petrophysical, and fluid properties. It is also capable of assessing impact of well configuration, spacing, steam quality, and steaming strategy.
Toolstring Impact Sensors
Authors: McLaughlin Stuart , Mclauchlan Alan 
Published: December 2007

Abstract
Since the application of slickline technology for wellbore intervention, the need for a measurement device to determine not only strain on the wire but forces applied to the toolstring at depth has been required.
What stands between a successful intervention and a ‘miss-run’ is the skill of the slickline operator and the surface weight indicator known as a load cell.
This paper will address the lesson learned from applying ‘Impact Sensors’ to slickline toolstrings in over 100 applications since it's launch in September 2005. The paper will also cover a case study that utilized the technology to better understand downhole conditions and their effects on toolstrings of various geometries. Completion technology has altered greatly and the results of directional drilling technology and horizontal completion architecture have proven to enhance the delivery of hydrocarbons to surface.
The application of new technology has been implemented by the Electric Line, Coil Tubing, Drilling, Reservoir Analysis and other groups in the industry, however the application of new technology to the slick line intervention business has been greatly lacking and because of this many completion engineers develop completion installation programs with the least amount of wire in the hole as possible.
Much of this reluctance is due to the perceived risk associated with deploying slick line into the well bore where an ‘unknown event’ may cause irreparable damage to the completion system or at the very least a costly exercise in equipment recovery.
The application of impact sensors to the slick line toolstring eliminates much of associate unknown risk factors by supplying the operator with known parameters being applied at depth.
Drilling Performance Management System
Authors: Rahil A. 
Published: December 2007

Abstract
Despite the capital intensive nature of drilling operations, drilling analysis is not routinely practiced as it should be. This is understandable since drilling engineers are principally rewarded for well planning and well construction. Therefore, the need to encourage best practices and continuous learning is a key to drilling improvement. Otherwise, the history will repeat itself "If you always do what you have always done, you will always get what you have always got".
In that purpose, the asset management tools and techniques introduced in this study can be effectively deployed in the analysis of drilling performance, they help to detect new opportunities, quantify and address removable lost time and analyse the major problems in a structured manner.
The aim of this study is to provide drilling team with a significant process to improve drilling performance, and set up a benchmarking process that becomes "a necessity for survival" as soon as the organization realizes there is someone else doing the same thing but better
This paper illustrates a case study of Hassi Messaoud field, it follows these steps:
What is the current performance in terms of time and cost? How do we benchmark with pacesetter in the area? How much this performance could be improved? What is the Road map of managing drilling performance in order to get improved?
The paper ends up with a structured methodology presented in a simple process flow incorporating some of the asset management tools and techniques with the results. It represents the drilling performance management system that can promote drilling efficiency and ensures a continuous learning through systematic analysis of historical data, and thereby, challenge well planning and construction.
Some enablers of the system are listed at the end. Then, conclusion and recommendations for further studies based on the system limitations are finally proposed.
Integration of Subsurface, Surface and Economics Under Uncertainty in Orocual Field
Authors: Rodríguez Rosa , Solano Karen , Guevara Siulenna , Velásquez María , Saputelli Luigi 
Published: December 2007

Abstract
Orocual field is one of the largest growing onshore opportunities in North of Monagas basin, eastern Venezuela. The field is planning to increase its production potential to more than 500% in the next five years. Business plan involve new expansion opportunities with improving field economics. These opportunities include massive development of the shallow heavy oil horizons by steam injection and development drilling in the deeper light and condensate reservoirs. To accomplish such a challenging goal, it was necessary to estimate new requirements for surface facilities while considering both reservoir uncertainties and multiple development scenarios.
This paper presents a unique and innovated method and a case-study for integrating multiple-reservoir forecasts with a surface facilities network, with economics and uncertainty. Subsurface responses from five Orocual formations were obtained from ten different reservoir simulation models with their associated well constraints. One single surface network model was used to gather production information from all the reservoirs and likewise was used to develop alternate production scenarios. An automated workflow handled the integration of reservoir production uncertainty, drilling schedule compliance, workover success, economics and varying surface facilities capacities.
The procedure that we have developed in this effort permitted the visualization of a more realistic asset performance compared to requirements in the long-term. The procedure also identified future needs for artificial lift.
The methodology developed also served as a platform for the exhaustive optimization of wellbore and surface equipment sizing in the presence of uncertainties based on front-end-loading (FEL) methodology. The procedure allowed the evaluation of parameters that affect uncertainty in well productivity, drilling schedule compliance, workover success, and varying surface facilities capacities, such as project execution time, workover success, facilities uptime, and facilities spare capacity.
3D Modeling of Tracer Experiments to Determine Gas Trapping in Foam in Porous Media
Authors: Li Z. , Rossen W. R. , Nguyen Q. P. 
Published: December 2007

Abstract
Foam diversion is used worldwide in acid matrix-stimulation treatments. Gas trapping is a crucial component of foam mobility and diversion. Previous studies have estimated trapped-gas saturation from a fit of coreflood effluent profiles of one or more gas tracers to a one-dimensional (1D) model for tracer mass transfer. A major factor in these experiments is diffusion of tracer between flowing and trapped gas.
We previously reported x-ray computed tomography (CT) images of Xe tracer injected during steady-state foam flow, which for the first time allowed direct visualization of the location of tracer in the core throughout the experiment. Here we extend the study by analyzing the diffusion of tracer through trapped foam in 3D. Cross-sectional CT images show that in this experiment tracer did not flow through the core evenly, but mostly along the top and sides of the core. Within these regions, tracer flowed in pathways separated by distances of a few mm. Modeling suggests that tracer diffused through trapped gas between the flowing gas pathways quickly, while mass transfer between the larger region and foam in the rest of the core was slower.
A three-dimensional (3D) model of flow and diffusion of tracer can fit the effluent data from the previous experiment quantitatively and fit CT images qualitatively. Moreover, the model fits the data well with values of flowing-gas fraction that differ by a factor of 2 (0.25 and 0.51).
We test four published methods of inferring flowing-gas fraction against our synthetic data: the method of Friedmann et al., based on early breakthrough of tracer; fitting effluent data with a 1D mass-transfer model, using one or two tracers; and the method of Nguyen et al. (2007), based on a break in a plot of average tracer concentration in a given cross-section as a function of time. None of these methods were able to distinguish between the two cases with different flowing-gas fractions. Using the 1D model fitted to results for two tracers with different diffusion coefficients gave less-accurate results than a fit using the slower-diffusing tracer alone.