bluuebunny/crossref_metadata_2025_split huggingface dataset:
Connectivity of Spatially Correlated Fractures: Simulation and Field Studies
Authors: Masihi Mohsen , King Peter 
Published: December 2007

Abstract
The nature of fluid flow in fractured reservoirs of very low matrix permeability depends on the geometrical properties of fractures as well as the connectivity of the fracture network. Percolation theory is the obvious tool to rapidly estimate the connectivity and its associated uncertainty through some algebraic scaling laws. However, the usual scaling laws do not consider anisotropy, fracture size distribution and fractures’ interactions. We have recently addressed the effects of anisotropy in orientation of fractures (SPE 94186) and fracture length distribution (SPE 100229) on the scaling law of the connectivity. Poisson distribution of fractures assumed by standard percolation is also in contradiction with the existence of fracture sets or the observed spatial correlation between natural fractures over scales.
In this study we first present a simple geomechanical fracture model with which we can investigate the effect of fracture spatial correlation on the network connectivity. We assume that all fracturing has happened and has achieved mechanical equilibrium which enables us to use entropy arguments and statistical mechanics to model fractures. With this, we use the realizations of correlated fracture networks in the basic methodology of the percolation and investigate the network connectivity. In particular, the simulation results show that the scaling exponents of the connectivity are different from the conventional, uncorrelated values.
We then use the field data of minerilaized fractures exposed on the southern margin of the Bristol Channel Basin to investigate the percolation behavior of the correlated fractures. We show that the connectivity predictions from the percolation approach are in agreement with the results calculated from field data with the advantage that they can be obtained very quickly. As a result this extends the applicability of percolation approach to correlated fractures which may be used for practical engineering purposes.
Multiple Slug Scaling of Linear and Pattern Laboratory Chemical Floods
Authors: Haskin Helen Kay , Davis Lorne Arthur 
Published: December 2007

Abstract
The screening and design of chemical flood processes requires an understanding of the effects of each chemical slug on oil recovery. The concept of volumetric linear scaling can be extended to processes involving the injection of multiple chemical slugs as long as the relative ratios of slug sizes are held constant. This allows fast development of the relation between oil recovery and slug size requirements for each chemical injected based on only a few laboratory linear floods.
Linear floods were conducted in a synthetic water-wet matrix. The multiple slug scaling approach used oil saturation distributions measured by microwave attenuation in one laboratory flood to predict accurately the tertiary residual oil saturation and tertiary oil breakthrough in another laboratory linear flood run with larger slug sizes. Oil saturation distributions at 0.11 V/Vp intervals during the flood, as well as at Sorc, were also accurately predicted.
A laboratory quarter five-spot pattern flood involving sequential injection of a small surfactant slug, a small polymer slug, and continuous drive water was run in a water-wet synthetic matrix. Linear flood oil saturation distributions were scaled to predict the oil saturation distributions in the pattern using a fixed twelve streamtube model for the flow. Details of this scaling procedure are given. Residual tertiary oil saturation, tertiary recovery, and oil saturation changes with time were predicted to within the experimental errors involved in the procedures. The observed tertiary oil breakthrough was later than predicted. Observed oil saturation distributions tended to show more oil left in the corners of the model than predicted by the scaling theory. These secondary effects and the overall behavior of the pattern flood are considered in terms of the chosen streamtube network and the assumptions of stable unit mobility flow.
Flow Assurance: Reliable and Accurate Prediction of the Viscosity of Natural Gas
Authors: Vesovic V. 
Published: December 2007

Abstract
Modern viscosity prediction methods have to satisfy the requirements for flow assurance and reliable reservoir characterization by demonstrably predicting accurate, reliable and internally consistent viscosity data. The best way to achieve this is by employing predictive methods based on the best available theory, simplified, just sufficiently to allow ready application and validated against a critical set of primary experimental data of proven accuracy.
The presented VW methodology is one such method, that is based on the kinetic theory of rigid spheres, modified to take into account the behavior of real fluids. It has no adjustable parameters, and requires no dense mixture viscosity data. In this work, the VW method was validated against a new set of natural gas viscosity data of very high accuracy. The experimental data were predicted with an rms deviation of the order of 0.5%-1%, commensurate with the experimental accuracy of the data. Overall, it is estimated that the VW method can predict the viscosity of natural gas within ±2% in the temperature region 260 K - 400 K and pressures up to 200 bars, with the accuracy deteriorating slightly at higher pressures and lower temperatures. It can be used to predict the viscosity of CO2-rich, sour and wet natural gas.
Interpretation of Post Deep-Acidizing Pressure Tests in a Naturally Fractured Reservoir
Authors: Bensalem Omar , Tiab Djebbar 
Published: December 2007

Abstract
Acidizing wells after completion or even after some period of production is a standard practice in naturally fractured reservoirs. Such a practice allows easier and faster removal of mud materials from the fractures intersecting the well. In some reservoirs, acidizing is performed deep into the formation for the purpose of enlarging the width of fissures and enhancing their interconnectivity. This results in a composite system with two zones, each having different characteristics, including storage capacity ratio, interporosity flow coefficient, and permeability. Composite systems may also result from fluid injection. High injection of fluids causes larger opening of fractures near the wellbore (due to higher pore pressure), which results in an increase of fracture permeability around the well.
In this paper the inner zone is considered to be finite, but the outer zone can be bounded or infinite. A model for a composite naturally fractured system has been developed by assuming pseudo-steady state fluid transfer from matrix to fractures, and taking into consideration the effects of: wellbore storage, near-wellbore formation damage and skin at the interface of the two zones. The loglog plots of the pressure and pressure derivative as a function of the storage capacity and permeability ratios of the two zones provide unique characteristics, which were used to derive equations for calculating the parameters of the two zones, radius of the inner zone, mechanical skin ,and skin at the interface.
From the interpretation of the loglog plots of the pressure and pressure derivative data, using Tiab's Direct Synthesis (TDS) technique, we have found that: (1) the contribution of the matrix to the flow can occur in the inner zone or the outer zone, depending on the product of the interporosity flow factor and radius of the inner zone; (2) When the ratio of the dimensionless radius of the two zones is less than ten, the naturally fractured reservoir behaves like a homogeneous system; (3) For storage capacity and permeability ratios greater than unity, the pressure derivative curve has a hump, which may appear before or after the trough; the coordinates of this maximum point may be used to calculate the permeability of the outer zone in the absence of the second radial flow line; and (4) the presence of a thin skin zone at the interface influences the starting time of the radial flow line of the outer zone. Several numerical examples are included in the paper.
Validation of History Matching Results Achieved by Multiscale Methods
Authors: Valestrand Randi , Nævdal Geir 
Published: December 2007

Abstract
A widely used method for finding unknown reservoir properties is estimating them as parameters through history matching. There is a risk that the parameter estimation will fail using this technique, because: A) It is an ill-posed inverse problem, and/or B) The reservoir model could contain model errors. In history matching the success of the estimation is validated by how well the data are matched, but there is a risk that the estimation has failed due to A) or B) even though the data are matched.
In this paper we present a method for identifying when the history matching estimation has failed. Moreover, the method is helpful in deciding when to stop the estimation procedure.
The validation method presented here is developed for multiscale estimation techniques and consist of the following: The objective function (measure of data-match) and the property to be estimated are predicted by analytical calculations. We then perform the estimation while comparing the development of the estimated and predicted values. How close the predicted and the estimated values are, is used to indicate success or failure.
The validation method is illustrated on two examples where we estimate the absolute permeability from reservoir production data. One of the examples is a simple 2D synthetic case while the other is a simplified 2D model generated by using a single horizontal layer from a North Sea field model.
EOR Evaluation Method for Highly Heterogeneous and Complex Reservoirs
Authors: Figuera L. , Khan K. , Quijada D. , Maestracci W. 
Published: December 2007

Abstract
Giant reservoirs in North of Monagas in Venezuela have been submitted to Waterflooding (since 1993) and Gas injection (since 1998) to support the oil production. currently the oil production is around 840 MBNPD. Those highly heterogeneous reservoirs are deep, with high pressure and temperature and presenting compositional fluid variation with depth. In order to maximize the reserves of these reservoirs the feasibility of applying EOR processes have been analyzed. Several existing methodologies and commercial software packages designed for the evaluation of EOR processes do not offer the aduate support for the decision making in highly heterogeneous and complex reservoirs.
An integrated methodology has been proposed to evaluate and select the possible EOR processes in the North of Monagas. The methodology is based on a combination of economical criteria, recovery improvement and risk analysis.
The methodology can be structured in three stages. In stage I, multiple analytical methodologies for the pre selection of all applicable processes are integrated. During stage II, the uncertainty associated with each pre selected process is assessed through the areal, vertical and displacement sweep efficiencies evaluation using 1D and 2D numerical simulation models. In Stage III, each process is evaluated at 3D full-field scale and a risk analysis is performed as a function of stage II results.
The proposed methodology states a structured way for the evaluation and selection of EOR processes in complex and a heterogeneous reservoir, which integrates conventional analyses, numerical simulation and risk analysis as decision tools. This paper enhances existing methodologies for the evaluation of EOR processes.
The Isenhour Unit — A Unique Polymer-Augmented Alkaline Flood
Authors: Sloat Ben , Zlomke Darrell 
Published: December 2007

Abstract
The Almy sands in Sublette County, Wyoming have been subjected to various volumetric sweep improvement techniques since September, 1969. This paper describes the first field wide effort to reduce residual oil saturation in the swept area.
Initially, a series of crude oil - alkaline agent screening tests were run to select, on the basis of interfacial tension reduction (IFT), the most cost effective alkaline agent. Follow up core tests showed that a combination of soda ash (Na2CO3) and anionic polymer would be effective in reducing oil saturations from 22 to 17 percent pore volume. The core tests also demonstrated that a properly prepared alkaline solution could be injected into the high clay content Almy. On the basis of these test results and ten years of experience injecting clay stabilizers, anionic polymers and wettability alteration products, the decision was made to go from the start with a total oil recovery program.
The original plant design was modified to accommodate the requirements for adding one half million pounds of Na2CO3 in less than a year. This involved installing a second dry solids feed system, interchangeable with the regular polymer unit. Storage capacity at the plant site was increased to 50,000 pounds of dry product and on the Na2CO3 unit a second 100 gallon stainless steel solution tank was put in series with the regular mix tank. Operating people designed and built a rugged, inexpensive product handling system that allows the plant operator to service both feed units in less than one hour a day.
Input side control tests include pH, O2, PO4, turbidity, screen factor and viscosity. Hall Plots are the primary monitor of injection well conditions with step rate tests and pressure fall-off measurements used as back up.
Producing wells are tested once a month. Data is plotted on a time-rate basis as well as graphed in the form of water-oil ratio (WOR) vs. cumulative oil recovery.
Produced water samples are checked for pH, chloride, tracers (thiocyanate and nitrate) and polymer breakthru. These results are also posted on the individual producing well graphs.
Although only in its third year of operation, the project is far enough along to conclude the following:
It is practical and profitable to employ, at the same time, techniques that will improve sweep and lower residual oil saturation. Selecting a "Total Oil Recovery" process and starting it early greatly simplifies plant design. EOR processes requiring fresh water should be started before breakthru to lower costs and lessen the problems related to lifting, treating and reuse or disposal of produced water.
Gravity Segregation in Gas-Injection IOR
Authors: Rossen W. R. , Shen C. 
Published: December 2007

Abstract
This paper presents a survey of simple methods for estimating vertical sweep efficiency in improved oil recovery (IOR) by gas injection.
A useful model for gravity override in gas IOR is that of Stone and Jenkins (SPE 11130, 12632), which applies to simultaneous water-gas injection into a homogeneous reservoir. Their equations for the distance to complete segregation are rigorously correct as long as the usual assumptions of fractional-flow theory apply. Their model implies that the volume swept by gas at given injection rate is approximately the same for vertical and horizontal wells, but the injection pressure does depend on well geometry and injection interval. For a given well geometry, the distance gas can travel before segregation depends directly on injection pressure. Thus, if injection pressure is limited, it is crucial to choose an injection profile that maximizes injectivity.
Recently, Stone (SPE 91724) suggested a new method of injection: gas and water injected simultaneously but separately, with water injected higher in the interval than gas. At fixed total injection rate, injection of water above gas gives deeper penetration before complete segregation than does coinjection in two-dimensional modeling and simulations. Whether injecting water above gas or both together, using only a portion of the injection interval reduces injectivity without affecting the distance to the point of segregation.
These results apply to both gas and foam IOR as long as gas and water are injected simultaneously or in separate, small slugs.
The MEG (Mono Ethylene) Injection Gas Dehydration Process Evaluation for the Margarita Field Development
Authors: Vergara Contreras Moises Alfredo , Foucart Nicolas 
Published: December 2007

Abstract
The objective of the study is to select the gas dehydration process system within the Margarita Field Development Project based on "MEG (MONO ETHYLENE) Injection with Mechanical Refrigeration" and compare it with the "Glycol Dehydration Process System", from the technological and economical point of view.
The dehydration process based on TEG is the most common process for natural gas dehydration; it is an efficient technology and its operation is very well known.
In order to reduce the CAPEX and OPEX of the Project, the operator has studied potential process options. One way to optimize the gas dehydration process is by simplifying and combining it with other processes, which is the case when considering the combined MEG injection with mechanical refrigeration, a common practice in the Industry.
The scope of this report covers:
○ Estimate of the downstream and utility equipments as required (glycol loss, glycol rate recirculation, electrical requirements, etc) ○ Cost Estimate (OPEX / CAPEX). ○ Explanation of uncertainties and risks that may be associated in applying the dehydration process on this particular application, and steps (if required) to eliminate those uncertainties. ○ To take experience of similar plants with similar requirement.
The MEG Injection together with a Dew Point Plant is able to dehydrate the natural gas, because the chiller unit operates at low temperatures and it permits the water content of the gas to be condensed and removed in "cold separation", but this process requires inhibitor injection in order to avoid hydration formation, being glycol the usual inhibitor. Removing the Contactor Tower and changing TEG by MEG has little impact in the Dew Point Plant design. The additional power required in the propane compressor is compensated in the glycol pump which is lower power consumption because the MEG injection rate is lower than the TEG one.
The different aspects evaluated between MEG Injection and Contactor Tower with TEG, are favorable toward the MEG Injection as:
○ CAPEX: FOB Cost. ○ MEG Injection saves MEG regeneration unit which is smaller and lighter. ○ Elimination of TEG contactors will simplify the plant, reduce installation cost and avoid large heavy vessels with transportation constraints. ○ MEG injection is easier to regenerate than TEG and alleviates environmental issues with BTEX emission.
After taking in consideration all the points in favor of the MEG Injection, it is recommended to install it in the Gas Treatment Plant.
Anisotropic PP and PSv Prestack Depth Migration of 4C (OBC) Seismic Data, Pamberi, Offshore Trinidad
Authors: Johns T. D. , Vito C. , Sarmiento R. 
Published: December 2007

Abstract
In November 2004, EOG Resources acquired an ocean-bottom cable (OBC) 4C swath survey across the Pamberi-1 well location in the Lower Reverse L block of the Columbus basin, eastern offshore Trinidad. The purpose of the 4C test survey was to evaluate the potential of long-offset multicomponent technology for resolving lithology and stratigraphic detail in an area perturbed by shallow gas, overpressure and illumination shadows from normal regional faults and major anticlinal ridge trends acting as pressure seals. The motivation from EOG for attempting this was because a conventional 3D towed-streamer survey acquired the previous year failed to adequately image the target reflectors comprising the reservoir under the main growth fault.
Details of the P- and PSv-wave processing of this dataset through anisotropic prestack time migration were previously described (Johns et al., 2006) in which it was demonstrated there existed a qualitative correlation between derived parameters and attributes from P and Sv anisotropic migration velocities and known regional geology. This observation was quite remarkable considering only a limited effort to constrain or validate parameters (in this case, velocities to the Pamberi-1 well checkshots) was performed. Under the "Future work" section of the previous publication, it was suggested that further data quality enhancement in preparation for more quantitative rock property classification, calibrated to wells, could only be achieved after prestack depth imaging.
In this paper, we present precisely that next phase in the 4C processing, advancing the P- and PSv-wave data through anisotropic prestack depth migration, using cell-based tomography with a top-down pseudo layer-stripping approach. The Pamberi-1 well information was used to constrain the anisotropy in the shallow section, with the deeper, spatial trend away from the proximity of the well determined from the anisotropy derived previously in the time processing.
Prior to proceeding with the anisotropic depth imaging, the magnitude of shear splitting (or, birefringence) from the presence of azimuthal anisotropy (HTI) is first examined to assess its potential impact on the radial rotated P-S signal. The shear-wave splitting analysis revealed a principal angle of polarization that was closely aligned with the regional stress direction delineated by the major faults blocks acting as pressure seals.
Technical Feasibility of Chemical Flooding in California Reservoirs
Authors: Holm Leroy W. 
Published: December 2007

Abstract
A study of the applicability of chemical flooding to California reservoirs revealed a number of facts that may not be apparent to everyone. The five chemical flooding processes reviewed in this paper are carbon dioxide, micellar-polymer, polymer, caustic and hydrocarbon miscible.
In terms of enhanced oil recovery, California is by far the leading State in total oil production, number of projects, money invested, etc.(1) The EOR projects are mainly thermal, not chemical, but they account for about 75% of total EOR production in the U.S. (Fig. 1.). These EOR projects have helped California to maintain its production and reserves during the past ten years while other major oil producing states (Texas, Louisiansu Oklahoma) have experienced substantial declines.(2) (Figs. 2 and 3).
Although California is thought of primarily as a source of heavy, low gravity crude oil with potential for only thermal processes, over one half of the 435 California reservoirs on which DOE has crude oil data(3) contain oils with gravities of 25° API or higher and viscosities of less than 20 cp. These reservoirs include sands in the large Wilmington, Belridge, Coalinga, Ventura and Midway Sunset fields. Based on crude oil properties, these reservoirs are candidates for all of the chemical flooding processes (miscible and non miscible). And, some of the largest of the chemical flood projects in the U.S. are already underway in California in the Wilmington, Huntington Beach, Coalihga and Orcutt Hills fields. (Table 1).