bluuebunny/crossref_metadata_2025_split huggingface dataset:
History Matching with an Uncertain Geological Scenario
Authors: Suzuki S. , Caers J. 
Published: December 2007

Abstract
With the increased emphasis on accurately representing geological variability / uncertainty in modeling heterogeneous reservoirs, the goal of modern history matching methods is not only to reproduce the past production behavior; it also aims at preserving geological realism. However, in complex geological environments, with limited access to the subsurface (e.g. deepwater/turbidite systems), the geological scenario governing the spatial distribution of important reservoir properties such as facies type / permeability is uncertain. Indeed, with few wells and limited seismic resolution, an accurate determination of the geological depositional system may not be possible. In this paper, we propose a new history matching technique that can account for this first order uncertainty. At the same time, this method can be regarded as a way to reduce geological uncertainty by means of production data.
To model geological scenario uncertainty we rely on the field of multiple-point geostatistics, where each scenario is quantitatively depicted by a training image, a fully explicit reservoir analog of sorts. Given a training image, a geological model realization can be stochastically generated using geostatistical algorithms. A discrete set of such scenarios is assumed available from a careful geological uncertainty study. To solve the inverse problem of history matching one can no longer rely on the classical optimization with gradient formulation, due to the inherently discrete nature of the problem. Instead, we rely on stochastic search methods (such as the Neighborhood Algorithm), that search in the space of all geologically plausible model realizations for those that history match by considering a ‘similarity’ measure between such plausible geological model realizations. We show that the production response in the space defined by a suitable similarity measure is structured, i.e. not random, hence optimization/history matching with stochastic search methods is effective. Several realistic synthetic reservoir applications are presented to illustrate this methodology.
Onshore LNG Production Process Selection
Authors: Mokhatab S. , Economides M. J. 
Published: December 2007

Abstract
The refrigeration and liquefaction process is the key element of a liquid natural gas (LNG) project and for most estimates of under construction or contemplated projects it can consume about 35% of the capital expenditure and up to 50% of the subsequent operating costs. The latest figures by the time of this writing showed that the world liquefaction capacity was 17 Bcf/d, slated to increase to 41 Bcf/d by 2010. There are several different licensed processes available with varying degrees of application and experience. This paper presents a critical overview of the LNG process and an analysis of the main methods available for the liquefaction of natural gas in an onshore LNG plant. The paper also discusses selection issues relating to the main technologies that affect LNG plant configuration.
Optimizing Drilling Performance in Salym—The Best Of Russia Meets the Best of the West
Authors: Koole Koos 
Published: December 2007

Abstract
Salym Petroleum Development (SPD), a 50/50 joint venture between Shell Salym Development and Evikhon, has been developing the Salym group of oilfields in the heartlands of Western Siberia since September 2003.
Before drilling operations started in April 2004, the Russian well construction practices, materials and drilling equipment were studied. The study lasted for about one year and involved frequent site visits to Siberia. Based on the findings a well construction strategy was developed, that is based largely on Russian well construction materials, top end Russian drilling equipment, such as the Uralmash BU 3900 and 4500 drilling rigs, and Russian Oil field services, and combines them with those Western services and equipment that offer a clear advantage on overall drilling performance. Examples are utilization of Western topdrives, solids control equipment and performance downhole motors and MWD systems.
The rigs are operating on day rate contracts, with the SPD well engineering department driving the operational and HSE performance through the strict application of the Shell Trademarked "Drilling the Limit" performance process.
After 2 years of drilling it has become clear that this carefully selected well construction strategy brought SPD best in class drilling and HSE performance.
A New Method for Improving LWD Logging Depth
Authors: Chia C. R. , Laastad H. , Kostin A. , Hjortland F. , Bordakov G. 
Published: December 2007

Abstract
This paper will describe a new method for improving Logging While Drilling (LWD) depth accuracy. Case studies that describe this technique will also be presented. It is generally accepted that using the Drillers depth measurement for LWD applications has been the most practical solution to a complex depth problem. The various sources of depth errors have also been described and quantified in the industry. Two of the main contributors to drillpipe based depth error are mechanical stretch and thermal expansion. Of these, the mechanical stretch is governed largely by the well profile, linear weight of the pipe, and the frictional forces that can be calculated using industry standard torque and drag calculations. The coefficient of linear thermal expansion of the drillstring components and the distributed temperature of the drillstring assembly at the time of measurement govern the change in length due to temperature. To compensate for these effects requires a series of algorithms that identify the mechanical condition of the drillstring at the time of measurement based on the operational drilling mode. Then, a standard torque and drag model is used to calculate the mechanical stretch, and a thermal expansion algorithm subsequently applies the temperature component of the depth correction. The results of these computations are a corrected logging depth, and an improved time to depth conversion file that can be used to recalculate the logging data. The results from case study data strongly support that; uncorrected standard LWD depth accuracy today is often at least as good as that provided by comparable wireline logs; and that LWD depth can be significantly improved using this technique. This new method for improving logging depth will lead to enhanced single well evaluation and the improved well-to-well correlation of reservoir features, and hence the value of the reservoir model.
Enhancing Well Productivity After Hydraulic Fracturing in the Priobskoe Oilfield
Authors: Nikurova L. F. , Surtaev V. N. , Yamilov R. R. 
Published: December 2007

Abstract
This paper deals with hydraulic fracture treatment issues encountered in the Priobskoye field. The focus is the determination of fracture parameters and their variation with time.
As always there are two key parameters that control the treatment effictiveness: fracture length and fracture conductivity. It is well known that, often, the actual fracture parameters are never as good as those for which the fracture is supposed to be designed for. Different reasons have been advanced in the past to explain this disparity, such as failure to fill the fracture with proppant up to the top; inefficient proppant transport into the fracture; proppant settlement by gravity; porous pack damaged with fracturing fluid gel residue. In addition, the apparent fracture paprameters may be affected by multiphase flow; non-Darcy flow; and various combinations of the above causes. Isolating the individual impact may never be possible. Despite the many approaches to describe the process of fracture design and the subsequent fluid flow in the fracture, the actual post-treatment effectiveness has not been resolved yet.
The frac job analysis remains so far an urgent issue which puts a variety of challenges to the scientific community and petroleum engineers. Understanding all the phenomena that take place in the wellbore and in the reservoir during both the fracture job and the subsequent well production would allow the selection and design of appropriate fracture parameters for an economically sound field development plan.
Drilling-Fluid Design for Challenging Wells in the Andean Mountain Region
Authors: Ramirez M. , Clapper D. , Kenny P. 
Published: December 2007

Abstract
Wells drilled in the Andean Mountain region of South America present significant challenges as a result of both operational and environmental factors. Wells located in the foothills along the basin are particularly difficult due tectonic stresses and unstable, probably, micro-fractured shales. Operators have experienced difficulties drilling wells using both water-based and oil-based muds (OBM). Environmental regulations hinder the use of OBM in many of those areas due to the potential environmental impact and costs associated with waste disposal. In many cases OBM has not prevented wellbore instability problems. This paper explains how a lack of understanding of regional geology and the practice of using successful drilling fluid design and drilling practices from other areas has led to wellbore problems. The water phase salinity of OBM and the use of the appropriate inhibitors in the drilling fluid play a key role in the minimization of wellbore problems. Although reactive clays are present in all the shales along the basin, they represent only 30 to 40 percent of the clay fraction, while non-expandable kaolinite clays are the major clay components. This paper explains how physical/mechanical effects are more important than inhibition in controlling these shales. Moreover, in some cases "excessive inhibition" due the presence of shale inhibitors such us potassium and high water phase salinity in OBM exacerbate the problems. Pore pressure transmission caused by fluid invasion is a major contributor to the observed problems. A combination of operational practices and improved fluid design minimizes mud and filtrate invasion. Troublesome shales in the Andean basin include, from north to south, the La Rosa and Icotetea in Venezuela, the Carbonera, Leon and Villeta in Colombia, the Napo in Ecuador, the Chonta in Peru and the Los Monos in Bolivia and Argentina. Case histories involving these shales are presented. Contrary to experiences in many other parts of the world, high water phase salinity OBM and potassium based water-based mud (WBM) are not the answer to shale stability problems. Rather, mud sealing properties, correct chemical composition and appropriate drilling practices are the key factors in maintaining wellbore stability.
Means for Passive Inflow Control Upon Gas Breakthrough
Authors: Crow S. L. , Coronado M. P. , Mody R. K. 
Published: December 2007

Abstract
Generally, horizontally completed oil producers are susceptible to localized gas coning during their life due to the gas/oil contact encroaching the well bore. Even a small difference in permeability and/or relative permeability along the well bore can result in gas coning, which impacts oil production and gas handling issues. Production optimization can be achieved by selectively shutting in areas where gas coning has broken into the wellbore, thus improving drainage efficiency.
A new system has been developed to passively sense gas inflow into the well. Once gas is detected in sufficient levels a valve is activated which shuts off the flow path into the well. The valve is designed to detect fluid density changes, and will activate once a predetermined decrease in production fluid density is reached, indicating gas coning. Incorporated in a sand face screen completion, each screen joint includes a phase-sensitive valve that enables it to work independently of the others. This approach has the benefit of shutting off unwanted gas inflow without the need for costly well intervention. Used in conjunction with zone isolation packers to eliminate annular flow, flow normalization can be achieved across the production interval1. The design can also be adapted to shut off water flow, as well as gas, in the event of water coning into the wellbore.
This paper will detail the development process of this new passive gas shut-off valve, including laboratory testing performed to qualify the technology. Plans for full-scale two-phase flow testing, conducted in cooperation with a major North Sea operator, will also be discussed.
Impact-Fatigue Correction: Optimization on the Selection Criteria for Sucker-Rod Materials
Authors: Martínez A. , Jaimes A. , Serna J. A. , Uribe I. 
Published: December 2007

Abstract
In oil wells with beam pumping systems, sucker rods mainly failed by fatigue due to the fact that they operate under cycling tension stresses. Additionally, superficial defects could be generated during handling and operation of the rods, which favor the formation of fatigue cracks and consequently decreasing the original expected life of the rod. Because of a high rate of rod failures by fatigue, and the consequent increase in operational costs, a study was done to obtain experimental data that will be used for the selection and design of the sucker rods strings. Fatigue tests were done for new high strength sucker rods, selected at random in the filed, to determine the endurance fatigue limit. Four kinds of fatigue tests were done: a) the material was tested in the as received condition (normalize and tempering), b) tests were conducted with specimens having a superficial defect simulating a corrosion pit, c) same as b but samples were quenched and tempered. Material characterization was done for all tested rods, including tension, hardness and impact tests, metallographic analysis and chemical composition. The experimental results showed important fatigue differences among the material evaluated, the negative effect of the surface pitting, and the improvement of the fatigue resistance by quenching and tempering the rods. A correlation between the results of impact test, tension test and fatigue test was developed. The findings and conclusions of this study will help the design engineer in the selection process between different sucker rods in the market. Finally, a simpler test method is presented to predict the fatigue behavior between rods of similar specification but from different manufactures.
Ultralightweight and Gas Migration Slurries: An Excellent Solution for Gas Wells
Authors: Mata F. , Diaz C. , Villa Hugo 
Published: December 2007

Abstract
This paper shows the excellent results obtained using ultra lightweight and gas migration slurries (ULWGMS) on wells of San Joaquin and Santa Rosa fields, located in Anaco City, Eastern Venezuela.
There are several gas fields in Anaco area, with complex wells, due to their low frac gradients, pressurized water zones, depressurized gas zones, H2S and CO2 content, clay sands, and, in some cases, presence of micro fractures. These sands are also bounded by interbedded shales, with trapped gas and water, experiencing larges amount of losses of mineral oil mud, during drilling.
All these characteristics contributed to unsuccessful primary cement jobs in the past, attributed to inappropriate slurry designs, with unsuitable properties to deal with all the above factors. Statistics showed that 2 out of 3 wells in this field failed due lost circulation issues, requiring remedial cementing to address gas control, and water migration. Ultra lightweight slurries were conceived, with adequate mechanical properties (flexible and tension strengths), in addition to providing H2S and CO2 resistance.
The first 9.2 ppg ultra lightweight slurry was first used in 2003 in San Joaquin field, and indicated good isolation, by logs runned.
Subsequently, ultra lightweight slurries with densities from 9 to 11 ppg have been applied in 18 different wells in Anaco area, showing excellent zone isolation results, demonstrated by low water cut, and good bond logs.
Zonal Isolation Within Highly Fractured Carbonates in Southeastern Mexico—Special Cementing Operations
Authors: Vargas W. , Lozada M. A. , Ledesma C. E. , Caballero C. 
Published: December 2007

Abstract
Oil production from Southeastern Mexico mainly comes from highly fracturated carbonate reservoirs. The appropriate management of oil production, natural depletion of the reservoirs with time, and continuous upper movement of oil- water contact represent the biggest challenge to isolate properly the production zone in development wells drilled within the area.
Drilling these wells through pay zone typically requires special pressure managed drilling techniques that considers the use of Nitrogen; either as foaming agent of the base polymer drilling fluid or as two-phase component. It can allow achieving the low equivalent circulating densities needed to penetrate the depleted reservoirs. The geological complexity of the area, mainly represented by compartmentalized reservoirs delimited by multiple fractures tied to vertical heterogeneity of the production zone, comprised by limestone and dolomite separated by shaly cap rocks shows the complete picture of the final conditions of the well to be isolated.
In this paper a systematic approach is presented, not only to highlight the use of ultra-light cement slurries1, but to remark pre-planning, well preparation, downhole tools, equipment and techniques used for cement placement to achieve zonal isolation within target intervals and/or oil-water contact. The main challenge remains the ability to properly isolate intervals that present washouts of more than three times the nominal external diameter of the bit. Also, the omnipresence of very low pore pressures, as low a 0.30 g/cm3 (2.5 lb/gal) of equivalent circulating density.
Therefore, here are presented the different slurry types used to perform these special cementing jobs, and also the operating procedures used by the cement placement techniques. Several examples have been selected to support the effectiveness of the applied methodology. Even though examples are related to a particular location and circumstances within Southeastern Mexico, the designed slurries and placement techniques can be customized to be applied successfully in similar areas.
Modeling Nonisothermal Rapid Multiphase Flow in Wells Under Nonequilibrium Conditions
Authors: Michel G. , Civan F. 
Published: December 2007

Abstract
An improved non-isothermal mathematical model considering the non-equilibrium effects involved during rapid multiphase flow in wells is presented. The extent of the non-equilibrium effect on deviation from the equilibrium model predictions is delineated at various flow rates, fluid saturations, and temperatures. Applications for three-phase (oil/water/gas) systems are presented. The model presented here can be coupled with reservoir simulation for accurate representation of the well-fluid hydraulics under non-equilibrium and non-isothermal flow conditions.
New Modified Black-Oil Correlations for Gas Condensate and Volatile Oil Fluids
Authors: El-Banbi A. H. , Fattah K. A. , Sayyouh M. H. 
Published: December 2007

Abstract
Several authors have shown the applicability of modified black oil (MBO) approach for modeling gas condensate and volatile oil reservoirs. It was shown before that MBO could adequately replace compositional simulation in many applications. In this work, a new set of MBO PVT correlations was developed. The four PVT functions (oil-gas ratio, Rv, solution gas-oil ratio, Rs, oil formation volume factor, Bo, and gas formation volume factor, Bg) were investigated. According to our knowledge, no other correlation for calculating oil-gas ratio exists in the petroleum literature. Alternatively, oil-gas ratio (needed for material balance and reservoir simulation calculations of gas condensate and volatile oil reservoirs) had to be generated from a combination of laboratory experiments and elaborate calculation procedures using EOS models. In previous work, we found that Whitson and Torp method for generating Modified Black Oil (MBO) PVT properties yielded best results when compared with compositional simulation. This method (and the others available in the literature such as Coats’ and Walsh's) requires the use of data from PVT laboratory experiments and proper construction of EOS models. We used Whitson and Torp's method to generate our database of the MBO PVT curves used in developing our correlations after matching the PVT experimental results with an EOS model. For each one of the four PVT parameters, we used 1850 values obtained from PVT analysis of eight gas condensate fluid samples and 1180 values obtained from PVT analysis of five volatile oil fluid samples. The samples were selected to cover a wide range of fluid composition, condensate yield, reservoir temperature, and pressure. The data points were generated by extracting the PVT properties of each sample at six different separator conditions. We then used multi-variable regression techniques to calculate our correlation constants.
The new correlations were validated using the generalized material balance equation calculations with data generated from a compositional reservoir simulator.
These new correlations depend only on readily available parameters in the field and can have wide applications when representative fluid samples are not available.
Relative-Permeability Coupled Saturation-Height Models Based on Hydraulic (Flow) Units in a Gas Field
Authors: Amabeoku M. O. , Kersey D. G. , BinNasser R. H. , Belowi A. R. 
Published: December 2007

Abstract
Saturation-height functions based on unique flow units have been developed as part of an integrated petrophysical analysis of a gas field. Furthermore, coupling the saturation functions with appropriate relative permeability models has effectively quantified hydrocarbon saturation, classified producibility of intervals and defined critical water saturation. The results show that linking depositional and diagenetic rock fabric to flow units, and then linking the flow units to zones with similar core capillary pressure and relative permeability relationships, have enhanced the utility of the saturation models. The saturation-height functions provided accurate water saturation, and they can potentially overcome uncertainties associated with log interpretation, using Archie or shaly sand models.
The saturation-height models were developed from core capillary pressure (Pc) data to calculate water saturation versus depth, which is independent of logs. The relative permeability models were obtained from special core analysis (SCAL). Consequently, the core-based saturation height functions can be useful in the calibration of log-based petrophysical models and, via relative permeability, can also be used to estimate water gas ratios and critical water saturation.
Capillary pressure and relative permeability curves from special core analysis studies were distributed into corresponding flow units, based on the calculated flow zone indicators. Saturation-height functions were then developed for each unit and used to calculate water saturation in the study field. The most accurate flow unit-based saturation model that evolved is a function of only porosity and height above free water level, does not require permeability in its application, and performed better than the Leverett J-function in this field.
Coupled with hydraulic unit (HU)-based relative permeability curves, the saturation models will provide more comprehensive petrophysical interpretation in gas bearing formations as well as highlight potential differences in reservoir producibility.