bluuebunny/crossref_metadata_2025_split huggingface dataset:
Fine Grid Simulation of Two-Phase Flow in Fractured Porous Media
Authors: Guzman R. E. , Aziz Khalid 
Published: December 2007

Abstract
Numerical reservoir simulation commonly divides naturally fractured reservoirs into matrix and fracture systems. The high permeability fractures are usually entirely responsible for flow between blocks and flow to the wells. The flow in these fractures is modeled using Darcy’s law and its extension to multiphase flow by means of relative permeabilities. The influence and measurement of fracture relative permeability for two-phase flow in fractured porous media have not been studied extensively. Transfer of fluids between the matrix and fractures is known to be one of the most important mechanisms of fluid movement in these reservoirs. Therefore, matrix/fracture fluid transfer, matrix and fracture two-phase flow, and interactions among them must be better understood for accurate simulation of oil recovery from naturally fractured reservoirs.
Experimental and numerical work on two-phase flow in fractured porous media has been initiated. The process considered is oil displacement by water in fractured porous media. Fine grid simulations of two-phase flow through a fractured core were performed in order to design the experiments and to study the effects of several key variables. These variables included fracture relative permeability, matrix/fracture capillary pressure, and matrix wettability. This paper presents the results obtained from the sensitivity analysis using fine grid simulations.
The numerical computations show that fracture relative permeabilities and wettability become important only at low capillary numbers. A dimensionless capillary number at which the fracture relative permeabilities become an important factor was estimated to be 20. The concept of a limiting capillary number may be extended to determine when fracture relative permeabilities are of influence in field scale simulations of naturally fractured reservoirs. Fracture capillary pressure was observed to have a negative effect on water imbibition, reducing the efficiency of the oil recovery. At high capillary numbers, i.e. when capillary forces are more important, water moves faster inside the matrix than in the fracture which results in high oil recovery. At lower capillary numbers, i.e. when viscous forces are more important, water channels rapidly through the fracture with a low recovery efficiency. Comparison of simulations of similar fractured and unfractured systems shows that at high capillary numbers the recovery is higher for the fractured core. At low capillary numbers the unfractured core exhibits higher recovery.
The Use of Geochemical Fingerprinting to Identify Migrated Gas at the Epps Underground Gas Storage Field
Authors: Coleman D. D. 
Published: December 2007

Abstract
The Epps Gas Storage Facility, operated by Trunkline Gas Company, is a converted gas field located in northeastern Louisiana. Gas was produced from what was originally defined as two different fields, Epps and South Epps, between 1928 and 1973. After depletion, the fields were converted to storage by Trunkline Gas Company and injection commenced in 1979. Between 1984 and 1987,11 production wells were drilled just to the west of the lease boundary. All of the wells were within 1/2 mile of the lease boundary, and some were only hundreds of feet away. By 1989 over 2 BCF of gas had been produced from these wells.
Geochemical fingerprinting has been used to demonstrate that a majority of the gas produced in the western area was not native gas, but was, in fact, storage gas which had migrated into the area. Plotting various chemical and isotopic parameters showed that the composition of the gas in some of the western wells had changed with time from that of native gas to that of storage gas. As a result of the geochemical, geological, and engineering studies that were carried out to verify gas migration, in 1990 the boundaries of the storage area were redefined by the Louisiana Office of Conservation to include these producing wells and thus protect the integrity of the storage project.
Simulation of a Successful Polymer Flood in the Chateaurenard Field
Authors: Takaqi Sunao , Pope G. A. , Sepehrnoori Kamy , Putz A. G. , BenDakhlia Hichem 
Published: December 2007

ABSTRACT
Early results of a successful polymer project started in 1985 in the Courtenay sand of the Chateaurenard field located south of Paris, France, were presented at the fall 1988 SPE meeting. We update these data and show that subsequent performance has confirmed the highly favorable oil recovery behavior of this project. The objective of this paper is to report the results of a detailed compositional simulation study conducted to understand this favorable result. Both alternative reservoir and process characteristics were investigated in these three-dimensional simulations. In particular, both a classical layered reservoir description and a geostatistical reservoir description were investigated. The latter represents a new approach to the interpretation of polymer flooding and played an important role in our study since the attenuation of reservoir heterogeneities is known to be an important attribute of polymer flooding. We also evaluated the importance of permeability reduction and adsorption of the polymer on process performance. After obtaining a good match of the production of oil, water and polymer, we then investigated the importance of design factors on the oil recovery performance. The actual polymer flood consisted of injecting a large polymer slug followed by five smaller slugs of decreasing polymer concentration to decrease the viscosity contrast with chase water, a classical polymer flooding design method called polymer grading. We found that this grading really made very little difference in the simulated oil recovery indicating that fingering was of little importance under these conditions. This was because the oil recovery was dominated by other factors such as polymer adsorption, fractional flow, and heterogeneity. Remarkably, this appears to be the first time that a study of this type with an accurate compositional simulator has been reported for polymer flooding. The combination of better reservoir characterization methodology and accurate process simulation of polymer flooding should aid in the successful exploitation of this technology in the future. This project clearly shows the high potential of polymer flooding under the appropriate reservoir conditions and with good design and implementation methods.
Mobility of Hydrocarbon Liquids in Gas Condensate Reservoirs: Interpretation of Depletion Laboratory Experiments
Authors: Morel D. C. , Lomer J-F. , Morineau Y. M. , Putz A. G. 
Published: December 2007

Abstract
When a rich gas field is put into production, one has to decide on a production mechanism which may involve either depletion, or partial or full pressure maintenance through gas or water injection. In order to reach a decision, it is essential to know not only the thermodynamics of the condensates but also the laws of their migration through the porous medium. This is achieved by a thermodynamic study, measurements of interfacial tensions between separate phases and by running a depletion experiment in bottom hole conditions. The interpretation of the set of measurements provides the necessary tools to run field scale simulations.
We present the study of the fluid behaviour of one of our newly discovered fields, the results of which were integrated in a full field study to define the scenarios of possible field production schemes.
The thermodynamic behaviour of the rich gas was represented by a Peng-Robinson equation of state involving seven pseudo components. The computed interfacial tensions between phases in equilibrium at different pressures ranged between .05 dyne/cm and 3 dyne/cm, they were very close to actual laboratory measurements. A depletion experiment was performed on a reconstituted 2 meters long core in bottom hole conditions (141°C, 400 bars initial pressure), the pressure was decreased very slowly, at less than 1 bar/day, and several stops were imposed to observe pure gravity drainage. Only a small fraction of the condensates was produced but the liquid breakthrough was observed very early during the depletion. The experiment was history matched with a compositional model, relative permeabilities for gravity drainage were deduced. It was necessary to introduce a dependence of the relative permeabilities on interfacial tensions below a threshold value of .15 dyne/cm.
Design and Performance of a Horizontal Well Waterflood Project in New Hope Shallow Unit, Franklin County, Texas
Authors: Huang W-S. , Kaetzer T. R. , Bowlin K. R. 
Published: December 2007

Abstract
In 1991, a pair of horizontal wells were drilled in the Pittsburg "C" sandstone reservoir of the New Hope Shallow Unit (NHSU) in East Texas. The first well was a 1500-ft horizontal oil well and the second was a 1500-ft water injection well.
The NHSU Pittsburg formation is a relatively tight sandstone reservoir undergoing a waterflood project expansion. It has a 45-year production history and is located at a depth of about 8000 feet. A single well model was used to predict horizontal well production potential and compare a horizontal development to a conventional vertical well development. After the initial evaluation appeared favorable, a fieldwide simulation study, including a 45-year history match and a horizontal well production forecast with and without a horizontal injection well, was made to further assess the project. Different scenarios were examined to determine the optimum development program. The wells were drilled in the last quarter of 1991. Actual production results appear to be tracking the forecast rates.
This paper summarizes the reservoir engineering studies performed as well as the planning, drilling and completion of these wells. Production histories as well as problems and their solutions to date are also documented. The application of horizontal wells in sandstone reservoirs demonstrates that new life can be brought to mature oil fields.
An Effective Matrix Stimulation Technique for Horizontal Wells
Authors: Tambini Mauro 
Published: December 2007

SUMMARY
This paper presents and discusses guidelines for matrix stimulation design, real-time control and post treatment evaluation on the basis of field results obtained from eight (8) horizontal and four (4) drain hole wells. A stimulation technique originally developed for vertical wells1, has been successfully modified and applied to horizontal wells. An optimized treatment procedure consists of placing the acid mixture downhole through coiled tubing and bullheading "ad hoc" volume of treating fluid at maximum bottom-hole pressure differential and rate. Equations to link measurable injection parameters (pressure and rate) with evolving skin effect are presented. In order to evaluate the effectiveness of the stimulation treatment, several Production Logs were run downhole using a coiled-tubing-conveyed wireline system. These revealed a remarkable distinct relationship between the producing horizontal length and the injection rate. A stimulation rate as high as 52 bbl/min (pumped in matrix, without fracturing, conditions) allowed almost total (95%) horizontal length contribution to the overall production. Without the use of diverting the technique was applied effectively to long horizontal production intervals (proven up to 1500 ft max).
The most effective results from this stimulation technique are obtained when dealing with reasonably homogeneous primary permeability reservoirs. For macrofractured formations (which are generally excellent candidates for horizontal wells) mechanical isolation plus the present technique is a more successful stimulation method to adequately cover the entire production interval.
Case histories are also described. A case of a stimulation repeated in the same well using different procedures is reported, as well as features of Production Logging Tools used in the field.
A Knowledge-Based Approach to Problem Identification in Producing Wells
Authors: Cosenza Giacomo , Tambini Mauro , Paccaloni Giovanni 
Published: December 2007

ABSTRACT
This paper presents a knowledge-based system (KBS) for the identification of problems in producing wells. The KBS is based on a general Well Problems Analysis (WPA) methodology that entails three main activities: verification of a problem's existence, identification of a preliminary set of possible problems, refinement of the most plausible problem(s). The relevant experts’ knowledge has been formalized by means of a classification approach based on the organization of all problems in a hierarchy of classes and, by associating the corresponding symptomatology with them. The system, validated at the company headquarters, is currently in use in the operating districts.
The system is a part of a more comprehensive project, called PROGRESS (PRoduction Optimization inteGRated Expert SystemS), aimed at providing a decision support system for well production optimization.
A Stochastic Fault Modeling Procedure Applied to a North Sea Reservoir
Authors: Selvig Arild , Fristad Torbjørn , Silseth J. K. , Madsen Rune 
Published: December 2007

ABSTRACT
In reservoirs with limited or poor seismic resolution, faults with throws below the seismic resolution can often act as flow-restricting barriers. Hence, the uncertainty related to the small-scale fault pattern may have significant impact on the precision of the production profile predictions and recovery estimates.
This paper discusses the impact of undetectable, small faults on the field production performance. A consistent methodology for incorporating the combined effect of uncertainty in the geometric fault pattern and uncertainty in the fault transmissibilities is presented. The subseismic faults are assigned to the numerical grid through a stochastic approach where fault densities, fault dimensions, and fault throw distributions are specified. In addition to the juxtaposition of the model layers at the various fault locations, alteration of flow potential across the faults (caused by for example mechanical or chemical sealing), is introduced as stochastic fault transmissibility multipliers.
An example, based on data from a highly overpressured North Sea reservoir which has been evaluated for a possible field development, is presented to illustrate the usefulness and flexibility of the proposed stochastic fault modeling procedure.
Extensional vs. Shear Fractures: Implications for Reservoir Characterisation
Authors: Loosveld R. J. H. , Franssen R. C. M. W. 
Published: December 2007

ABSTRACT
Fractured reservoirs are typically strongly anisotropic and heterogeneous, irrespective of whether the fractures are extensional or shearing-induced. Fracture network data are notoriously hard to obtain. Here, we present new results on fracture-network characteristics from outcrop and experimental studies.
In contrast to current views that fault and fracture patterns are of a fractal nature, these results demonstrate that extensional fractures (joints) are non-fractal. Shear fractures and faults, on the other hand, were found to agree with fractal concepts on a wide range of scales. They form scale-invariant patterns. Both fracture networks consisting of shear fractures and those consisting of joints have a high degree of fracture connectivity.
Extensional fractures tend to link with fractures of the same family and to abut against pre-existing joints. Blunting of joint tips at intersections also improves the connectivity of the fracture network. Monte Carlo simulation techniques have been used to determine the effective permeability of networks of extensional fractures. An outcrop-derived model yielded a markedly anisotropic bed-parallel permeability.
Localised shear failure in porous sandstones occurs by particulate flow or, more frequently, by cataclasis. Particulate flow leads to significant permeability increase whereas cataclasis may result in permeability increase or decrease, the latter being more common. Shear fractures are characterised by zones of anastomosing cataclastic deformation bands with enclosed lenses of undeformed matrix material. Thus, there will be no tortuous flow paths through these lenses around the tips of isolated deformation bands across the shear zone. Reservoir compartmentalisation may result from deformation bands which will have, at best, very subtle seismic expression.
On the Transport Properties of a Rod-Type Polymer in Sand Packs
Authors: van Domselaar H. R. , Fortmüller Claudia 
Published: December 2007

Abstract
Determination of rheological parameters of rod-type bio-polymer (Xanthan) solutions as a single (mobile) phase in sand packs is discussed. In one series residual oil is present.
Apparent viscosities approximated from sand pack experiments could be described by a Carreau type of equation. Since no real in situ polymer solution viscosities and permeabilities to these solutions can be determined up to now a practical way out of this problem is the determination of mobilities to the polymer solution with the help of the Darcy equation. These polymer mobilities can be described with a modified Carreau type of equation.
RF, RRF values and polymer mobilities are discussed in the context of apparent polymer viscosities.
Up-front and residual polymer retention have been estimated for conditions of 100 % accessible porevolume.
Pilot Testing of Membrane Technology to Selectively Remove Sulfate Ion from Seawater in the Wilmington Field
Authors: Scott J. A. 
Published: December 2007

ABSTRACT
Secondary recovery processes using highsulfate ion water sources can lead to reservoir souring. The waterflood operations for the Long Beach Unit of the East Wilmington Field are located in a highly urban and environmentally sensitive location in the Long Beach Harbor, California. One of the Unit's goals is to prevent reservoir souring. In addition, the formation water contains significant amounts of barium ion. Injection of highsulfate water sources results in barium sulfate precipitation and scaling of downhole pumps.
Pilot testing was conducted on membrane technology designed to selectively remove sulfate ion from open-ocean sea water. The pilot operation was installed on Island White of the Long Beach Unit. The process was evaluated to assess technical feasibility, characterize product water for reservoir compatibility, and compile operating data. Laboratory coreflooding experiments were conducted with the product water to evaluate reservoir compatibility because many of the producing zones are damage-prone.
The Impairment of Scale Inhibitor Function by Commonly Used Organic Anions
Authors: Barthorpe R. T. 
Published: December 2007

ABSTRACT
Trace amounts of metal chelant additives, commonly used in stimulation and fracture fluids, have been shown to have a debilitating effect upon the performance of widely used barium sulfate scale inhibitors. EDTA and citric and gluconic acids render examples of some commonly used scale inhibitors (phosphonates, polycarboxylates and phosphate esters) completely ineffective at concentrations as low as 0.1 mg/L. Such low concentrations may be expected to return from formation stimulation treatments for many months and would appear to jeopardize any scale inhibitor program in place. The testing was based upon a simulated North Sea scaling system at pH 4.0 and 6.0. Scale inhibitor concentrations studied were 50 and 100 mg/L The large negative effect of the organic chelants was observed at pH 4.0 and 6.0. The only scale inhibitors studied which remained ambivalent to these interferences were large polymeric vinylsulfonates.
Removal of Mineral Scale from Reservoir Core by Scale Dissolver
Authors: Rhudy J. S. 
Published: December 2007

ABSTRACT
The effectiveness of commercially available scale dissolvers for removing mineral scales from reservoir cores was studied in the laboratory. Fluids and preserved cores from a major North Sea reservoir were used. Equipment and procedures were developed to reproducibly deposit scale in reservoir cores. Then, the effectiveness of aminopolycarboxylic acid for removing scale from the cores was investigated. Deposition and dissolution of mineral scales were monitored by measurement of oil/water mobility in the core, effluent scale cation concentrations and scanning electron microscope observation. Mineral scales studied included calcite, barite and mixed scales.
The Modelling of Adsorption and Precipitation Scale Inhibitor Squeeze Treatments in North Sea Fields
Authors: Yuan Ming Dong , Sorbie K. S. , Todd A. C. , Atkinson L. M. , Riley Helen , Gurden Stuart 
Published: December 2007

Abstract
This paper presents an analyste and design study of field scale inhibitor squeeze treatments. Simulators of varying levels of complexity have been used to model squeeze data from several wells in North Sea fields. The modelling has been carried out both for simple single sandbody squeezes and for inhibitor treatments in heterogeneous systems where there is free crossflow between strata. The appropriately matched results are then used in the design of improved inhibitor squeeze strategies for the fields studied.
The main results from this study relate to the field design criteria which should be applied to both adsorption/desorption and "precipitation" scale inhibitor squeeze treatments. Using quite simple models to simulate the field results, a wide range of sensitivities in adsorption/desorption squeeze treatments has been investigated (e.g. injection concentration, overflush size, shut-in time etc). A more complex model was used to simulate an adsorption squeeze carried out in a multi-layer, near-well formation. Results show the significant effect of reservoir heterogeneity on inhibitor returns and, for such cases, that the placement strategy for inhibitor slug injection should be taken into consideration. A field "precipitation" squeeze has also been modelled which highlights the effect of local formation temperature. The results demonstrate the importance of selecting appropriate preflush and overflush volumes for creating the correct thermal conditions for in-situ inhibitor "precipitation".
A number of generally applicable conclusions arise from our study and some example economic results are presented. In particular, for precipitation type processes, some field application guidelines are given for the first time in the literature.
A New and Reliable Model for Predicting Oilfield Scale Formation
Authors: Yeboah Y. D. , Somuah S. K. , Saeed M. R. 
Published: December 2007

Abstract
A new and reliable Oilfield Scale Prediction Model (OSPMod) has been developed and is presented. Unlike the available models which predict only scaling potential using thermodynamics and limited solubility data, OSPMod predicts the potential and deposition profile based on extensive thermodynamic and kinetic data. The model uses experimental solubility data in NaCl, MgCl2, CaCl2, and their mixtures, and in natural oilfield brines to determine the saturation index. Critical saturation indices beyond which scaling occurs have been established for the common oilfield scales (BaSO4, SrSO4, CaSO4 nH2O, and CaCO3). The model uses the flow characteristics and experimental kinetic data to predict the scale deposition profile from the bottomhole to the surface, once the critical saturation index is exceeded. The model has been developed as a menu-driven, user-friendly software. It is applicable to all the common oilfield scales and provides several input, computation and output options. Graphic presentation of results is a useful feature of OSPMod. The accuracy, reliability, and key features of the model are illustrated in the text with oilfield and test well cases.