bluuebunny/crossref_metadata_2025_split huggingface dataset:
Water Breakthrough Numerical Simulation in Fractured Gas Reservoirs
Authors: Zhang Lie Hui , Feng Yi Yong 
Published: December 2007

Abstract
In the SiChuan gas fields of China, because of the complex geologic conditions, almost all the active water invasions appear to be water breakthrough along fractures. These seal the path of gas flowing in fractured gas reservoirs, as a result largely reducing the efficiency of gas production. Currently, it is very difficult to simulate such fracture water breakthrough using known fracture models (e.g, dual porosity, single permeability and dual porosity, dual permeability).
In this paper, we established a fracture water breakthrough numerical simulation model of water drive gas reservoir after we extensively investigated typical water breakthrough in SiChuan gas fields. Next, we applied this model to simulate the bottom water gas field of WeiYuan of SiChuan province and suggested effective water preventing measures. Then we gave four kinds of water invasion models: slow water coning, vertical water breakthrough, horizontal water breakthrough, vertical water breakthrough and horizontal breakthrough. Our simulation increased our knowledge of the mechanism of water invasion. Our models have been widely used in gas production in SiChuan fractured gas reservoirs.
P. 437
Improving Recovery through Peripheral Waterflood Management in Multilayered
Authors: Mamgai D.C. , Singh Lehmbar , Rangaraj S. , Singh Daljit 
Published: December 2007

Abstract
One of the Eocene age fields in Cambay Basin of India, having about 1000 MMbbls of initial oil implace, has got nine reservoirs of thickness varying from 14 ft to 66 ft. Two main multilayered reservoirs are being produced under peripheral water flood from early stage of exploitation. The estimated oil implace of these two reservoirs is 560 MMbbls and 170 MMbbls and expected ultimate recovery is 55 percent and 61 percent respectively. while about 82 percent of recoverable oil from these two reservoirs has been already recovered their present rate of production is 5200 BOPD with 72 percent of water.
Drilling of a few new wells for EOR, in the area that was expected to be flooded by encroaching injected water in the said two reservoirs has shown virgin oil saturation. On this basis, study of movement of advancing flood front in past - dynamic model, mapping of heterogeneity distribution pattern static model and, calculation of natural water influx and voidage have been taken up. Integration of these studies along with recovery analysis and cased hole carbon oxygen logging have been used in identifying areas of bypassed oil. The waterflood management by shift of injection row, regulation of injection rate and selective injection in low permeable layers in different flow regimes has been found to be effective in exploiting bypassed oil and improving sweep efficiency, in turn enhancing recovery and increasing oil production. Implementation of study in field has resulted in an increase in oil production form 1400 BOPD to 2000 BOPD from one sand.
The field has already produced 46.7 percent of total inplace oil in the last 35 years. The economic life the field will get extended by exploitation of bypassed oil and improvement in sweep efficiency through effective surveillance of water flood. P. 727
Journey From Well Logs/Cores to Integrated Geological and Petrophysical Properties
Authors: Bahar Asnul , Kelkar Mohan 
Published: December 2007

Abstract
Reservoir studies performed in the industry are currently moving towards an integrated approach. Most data available for this purpose are mainly from well cores and/or well logs. The translation of these data into the petrophysical properties, i.e., porosity and permeability, at interwell locations that are consistent with the underlying geological description is a critical process. This paper presents a methodology that can be used to achieve this goal. The method is validated through a field application.
The framework developed in this work starts with the given geological interpretation, i.e., facies and petrophysical properties, at well location. A new technique in evaluating the horizontal spatial relationship is provided. The technique uses the average properties of the vertical data to infer the low frequency characteristics of the horizontal data. Additionally, a correction in calculating indicator variogram, which is used to capture the facies' spatial relationship, is provided.
A new co-simulation technique to efficiently generate petrophysical properties consistent with the underlying geological description is also developed. The technique uses the conditional simulation tools of geostatistical methodology and has been successfully validated using the field data (sandstone and carbonate fields). The simulated geological descriptions matched well with the geologists' interpretation. All of these techniques are combined into a single user- friendly computer software that works on the PC platform.
P. 543
Defining Business Critical Workflows for Integrated Reservoir Optimization
Authors: Trayner P.M. 
Published: December 2007

Abstract
People remain Exploration and Production (E & P) companies' biggest asset, and yet, many studies show that, as an industry, we have struggled to harness the skills and knowledge of highly qualified professional staff in the critical business decisions needed in today's demanding environment.
The concepts of "Business Critical Workflow" and "Interpretation Cycle Time" will be shown to be crucial factors holding back our business. These represent the time it takes to design, collect, prepare, understand and take decisions from data, one of our other biggest assets. Today, this workflow is all too often a slow, inefficient and discontinuous process, and high risk business decisions are frequently taken without full recourse to all the available data, and more importantly to the knowledge derived from these data.
One of our key challenges is to align the business objectives of the various components of a typical E & P organization and to ensure that each of these components adds value throughout the E&P cycle. Thus we need to build a shared earth model for our oil and gas field prospects, which can be enhanced and used by all members of our business team, whether they are geologists, drillers, production engineers, geophysicists, economists or business managers. By reducing the time and effort needed to build, maintain and continuously update these models, the "Knowledge base" from our professional staff can be fully integrated and better utilized.
The generic use of modern software technologies will be illustrated with reference to several typical workflow scenarios. The adoption of industry standards will continue to be a key factor in the growth of such solutions, and in the future, E&P companies should have the opportunity to assemble applications from different vendors, without the need for time consuming data transfers from one platform to another. Standards will also bring a common application "look and feel" to users, irrespective of the data domain or application vendor, and such initiatives will help to reduce the learning curve for new or re-trained users. Vendors will undoubtedly continue to focus on ease of sue issues in their software development, but it will always be necessary for Oil companies to make the proper commitment in terms of relevant training and support infrastructure for the true (and significant) returns on investment to be realized.
P. 627
Techno-Economic and Risk Evaluation of an EOR Project
Authors: Joshi Sameer , Castanier Louis M. , Brigham William E. 
Published: December 2007

Abstract
The terms uncertainty and risk are never far off in the analysis of an exploration prospect or an oilfield investment project. Risk arises because there is uncertainty about the course of future events. Monte-Carlo simulation can be used to quantify risk. This process consists of treating uncertain input parameters of a problem as stochastic variables. All valid combinations of these input parameters are then tried, to simulate all possible outcomes. This results in specification of the model output as a statistical distribution of probable values.
The specific oilfield to which this analysis was applied is the Wilmington steamflood project previously operated by Union Pacific Resources (UPRC) at Long Beach, California. The methodology used is general and can be applied to any project which has uncertain input parameters. The software used will easily run on personal computers (PC's) and is available as an add-in program for a commonly used spreadsheet program for PC's.
Oil production rates for the steamflood had been predicted by using Ramey's generalization of Marx and Langenheim's method (SPE 29669). An economic analysis of the steamflood was carried Out using capital budgeting and discounted cash flow techniques. Monte-Carlo simulation was done for both the production rate calculations as well as the economic analysis. A statistical analysis of the oil production calculations and economic analysis was carried out, which also proved to be a sensitive method for checking the convergence of the Monte-Carlo simulation.
The simulation output consisted of probability distributions of produced oil volume, yearly cash flows, net present value (NPV) and internal rate of return (IRR) for the project.
P. 633
New Guidelines for Applying Curable Resin-Coated Proppants
Authors: Nguyen P.D. , Dusterhoft R.G. , Dewprashad B.T. , Weaver J.D. 
Published: December 2007

Abstract
Failures of resin-coated proppants have been primarily attributed to incompatibility between fluid chemistry and the resin, insufficient closure stress, the practice of flowing the well back too aggressively, or stress cycling. This paper describes the failure mechanism that may be more predominant than any of the others: curing too fast. Proppant consolidation kinetics were studied with the use of differential scanning calorimetry and compressive-strength development. Additional studies to determine ultimate compressive-strength development and the effects of flow erosion and stress cycling on resin-coated proppants were performed. This study has determined that the temperature profile and time before proppant grains are compacted and closure stress during curing are critical factors affecting consolidation properties. The investigation also resulted in the identification of the appropriate resin-coated proppants and guidelines for their uses in proppant flowback control in hard-rock fracturing and in sand control of soft formations as in screenless fracpack completions.
P. 587
Novel Application of Emulsified Acids to Matrix Stimulation of Heterogeneous Formations
Authors: Buijse M.A. , van Domelen M.S. 
Published: December 2007

M.A. Buijse, and M.S. van Domelen, SPE, Halliburton B.V

Abstract
Historically, emulsified acids have primarily been used in fracture acidising. By combining information from theoretical studies, experimental studies and field testing, a better understanding has recently been gained of the application of emulsified acids in matrix acidising. This paper discusses the use of emulsified acid as a stimulation fluid for matrix treatments in heterogeneous carbonate formations.
Theoretical and experimental studies published on the acid wormholing process in carbonate formations have shown the efficiency of systems that have low diffusion rates, for example acid-in-oil emulsion systems. Emulsified acid is especially effective when the injection rate is low, such as in low permeability formations or damaged formations. In these cases, plain HCl acid will spend on the formation face and will not create wormholes that penetrate deep into the formation. At comparable injection rates, emulsified acid is capable of forming deeply penetrating wormholes and efficiently stimulates the formation.
In this paper, results of flow tests are presented which compare the efficiency of emulsified acid with that of plain HCl acid. Several emulsified acid systems were tested. The effects of the injection rate, viscosity and acid/oil volume ratio were analyzed on core samples. Rheological properties and temperature stability (up to 250 F) of the emulsion systems were analyzed by means of Fann-50 tests.
Acid-in-oil emulsions are effective stimulation fluids in large intervals where streaks of high-permeability can act as thief zones. This is shown by means of example calculations of the fluid flow and distribution in a well.
Practical and economical aspects of mixing and pumping emulsified acid in the field will be discussed. Characteristics of candidate formations will be summarized and rules-of-thumb for preliminary treatment design will be presented.
P. 601
System Identification Approach to Watercut Analysis in Waterflooded Layered
Authors: Renard G. , Dembele D. , Lessi J. , Mari J.L. 
Published: December 2007

Abstract
Oil recovery in layered reservoirs within a complex geological structure is very often lower than expected. This is due both to the uncertainty in assessing hydraulic continuity between wells and to the trapping of oil in some unswept layers or field areas.
The symptoms of such a situation, for a well with commingled production from separate layers inequally waterflooded, may be erratic watercut variations. Such variations may be the result of interferences from surrounding injection and production wells that create changes in rate distribution between the various layers.
The objective of this paper is to present a new methodology to model the watercut of a producer as the response of a linear system using neighbouring well rates as inputs. The methodology based on a system identification approach implies the following steps: filtering of the raw data, selection of input wells by a technique of Main Component Analysis, identification of model coefficients by fitting the watercut of the modelled well over a restricted period of production, validation of the identified model and finally evaluation of the proper contribution of each input well.
The methodology has been applied to actual data from an area of the Arlan field in Russia. Models obtained were able to successfully forecast the watercut variations of most of the production wells over a several months period. It was then possible to use the geological model of the field area for interpreting these models in terms of main interactions between wells and sweep efficiency for each layer.
As shown in the paper, the proposed methodology has the potential (I) to define main hydraulic communications between wells, (II) to give a diagnosis on oil and water saturations of the different pay zones for a commingled producing well and (III) more generally to provide a predictive tool for the interpretation and improvement of the sweeping in layered reservoirs.
P. 35
Overview of Field Results Using TTBP as Effective Water Shut-Off Treatment In
Authors: Mohammed M.A. , Al-Mubarak M.A. , Al-Mulhim A.K. , Al-Mubarak S.M. , Al-Safi A.A. 
Published: December 2007

Abstract
Water shut-off treatments (WSOT) are routinely performed on wells in the carbonate formation, in one of Saudi Aramco's oil fields that are dead, have high water cut, or low-flowing wellhead pressure. WSOT using through-tubing bridge plugs (TTBT) in both open-hole and cased-hole completions have been employed. Such a treatment was successfully applied in zones that are 100% swept by the water flooding and are no longer contributing oil and in high permeability zones (super- K) located in the lower interval. These wells were then activated and have been placed on production. The field results from 40 bottom water shut-off jobs, using TTBP technique, are presented. The 1990-1996 water shut-off jobs added a total of 88.0 MBD of producible potential. In addition, the application of TTBP method increased recoverable reserves and avoided expensive workover costs.
This paper presents data to show that TTBP technique is very effective compared to other methods of water shut-off jobs. Significant cost reductions are realized. The success ratio of this treatment in the open-hole completion (OH) can be as high as the cased-hole (CH) completion, provided that a gauge' hole exists.
P. 147
Pore Scale Gravity Drainage under Different Wettabilities and Multiphase Coexistence
Authors: Saputelli Luigi A. , Dawe Richard , Grattoni Carlos 
Published: December 2007

Abstract
Improving the hydrocarbon recoveries for reserves is actually regarding new technologies and better porous media understanding. However, there is still a long way to go to improve efficiency, as many challenges remain. The arrangement and movement of three phases within the pore spaces are complex processes to model and comprehend.
In the porous medium, coexisting fluids with different densities are redistributed vertically by the force of gravity. Gravitational forces counteract with capillary and viscous forces; vertical barriers may also reduce gravitational performance as well. These divert forces often cause poor gravity segregation performance, leading to the trapping of the lighter phase fluid and consequent low hydrocarbon recoveries. Gravity forces play an important role in determining initial fluid distribution and at all stages of hydrocarbon reservoir development.
This project focuses on examining gravity effects that compete with capillary forces, under different scenarios of wettabilities, density differences, low interfacial tension differences and multi-phase coexistence. The objectives of the study are to understand physical interactions, the impact on oil recovery and to determine when they are important.
The physics of the processes surrounding gravity forces and their interaction with other reservoir parameters were thoroughly studied. In a three-phase system, it is seen that for the same positive spreading coefficient, the oil recovery kinetics is different and that gravity drainage is much less efficient in the oil-wet system, than in the water-wet. In oil- wet porous media, oil recovery by gravity drainage is independent of the spreading conditions. The Bond Number is appropriately corrected as a function of wettability and fluid saturation. Some corrections are pointed out in order to achieve proper modeling of reservoir fluid capabilities in the presence of gravity terms.
P. 179
Compositional and Relative Permeability Hysteresis Effects on Near-Miscible WAG
Authors: Christensen J.R. , Stenby E.H. , Skauge A. 
Published: December 2007

Abstract
Evaluation of compositional effects and fluid flow description on near-miscible (water-alternating-gas) WAG modeling have been studied for a North Sea oil field starting production in 1998. A sector model with four wells was applied to simulate a heterogeneous sandstone reservoir, and a compositional model was used to compare different production strategies e.g. waterflooding and a near-miscible (WAG) injection. In the WAG scheme both dry and wet (rich) hydrocarbon gases have been considered for injection. The phase behaviour was quantified by comparing the performance of the different injection gases.
Result obtained shows the WAG injection gives improved recovery compared to water injection, due to better sweep and lower residual oil saturation. Simulations with and without relative permeability hysteresis (two-phase model) were compared. The effect of trapped gas on oil recovery does not seem significant with the compositional model. The WAG process has been optimized with respect to slug size and the water-gas ratio.
A black-oil-model was generated tuned to fit the results from the compositional simulations. A WAG three-phase relative permeability hysteresis model using cycle dependent relative permeabilities for both wetting and non-wetting phases, have been compared to the standard two-phase Killough and Carlson hysteresis models. The results show significant lower gas ratio and a higher oil recovery for the WAG injection when using cycle dependent relative permeabilities.
The simulations show sensitivity toward the three-phase model whereas Carlsen/Killough type hysteresis has little/no influence on the oil recovery.
Simulations indicates that the recovery by WAG-injection may be underestimated in the compositional model due to lack of possibility for cycle dependent relative permeability hysteresis, whereas the black oil model underestimates the phase behaviour effect. The results indicate that the WAG- injection might have an upside potential with respect to the influence of combined phase behaviour and relative permeability effects.
P. 233
Use of Full-Field Simulation to Design a Miscible CO2 Flood
Authors: Brinkman F.P. , Kane T.V. , McCullough R.R. , Miertschin J.W. 
Published: December 2007

Abstract
A study using full-field reservoir modeling optimized the design of a miscible CO2 flood project for the Sharon Ridge Canyon Unit. The study began with extensive data gathering in the field and building a full-field 3D geologic model. A full-field simulation model with relatively coarse gridding was subsequently built and used to history match the waterflood. This waterflood model highlighted areas in the field with current high oil saturations as priority targets for CO2 flooding and generated a forecast of reserves from continued waterflooding. Predictions for the CO2 flood used an in-house 4-component simulator (stock tank: oil, solution gas, water, CO2). A full-field CO2 model with more finely gridded patterns was built using oil saturations and pressures at the end of history in the waterflood model. The CO2 model identified the best patterns for CO2 flooding and was instrumental in selecting a strategy for sizing the initial flood area and in determining the size, location, and timing of future expansions of the CO2 flood.
P. 265
Experimental Foundation for Relative Permeability Modeling of Foam
Authors: Vassenden F. , Holt T. 
Published: December 2007

Abstract
Optimization of foam treatments requires modeling or simulation of the process using a foam model that is capable of reproducing the critical properties of foam. The present work present a simple model that is based on the relative permeability concept, and is well suited for simulation of foam processes with conventional or slightly modified numerical simulators. The model can unify the understanding of a number of phenomena that characterizes foam flow. The validity of the model is substantiated by experimental data.
A consistent interpretation of foam breakdown, shear thinning effects, permeability effects, and effects of system pressure is possible with the presented model for gas relative permeability in a foam.
P. 73