bluuebunny/crossref_metadata_2025_split huggingface dataset:
Data Acquisition Design and Implementation: Opportunities and Challenges for Effective Programs in Mature Reservoirs
Authors: Pande P. K. , Clark M. B. , Blasingame T. A. , Doublet L. 
Published: December 2007

SUMMARY
Data acquisition design and implementation challenges for mature reservoirs which are targets for Improved Oil Recovery (IOR) applications are discussed in this paper. Examples are provided for Shallow Shelf Carbonate (SSC) reservoirs in the Permian Basin of West Texas.

What Are Mature Reservoirs?
Mature reservoirs are defined as properties with additional recovery potential by implementation of advanced reservoir characterization tools and techniques, reservoir management and/or changes in recovery mechanisms. Attributes of mature reservoirs are depicted in Figure 1, which shows the importance of reservoir characterization as a function of field development stage. Reservoir characterization and an understanding of heterogeneity become more important for maturing reservoirs as these factors have a profound impact on future reservoir development and management strategies. Mature reservoirs are typically characterized by some type of secondary drive mechanism. A change to a tertiary mode or implementation of other IOR methods may be necessary to extend the economic limit and productive life of the field.
In recently discovered reservoirs, advances in reservoir management technologies and practices allow operators the opportunity to implement timely, judicious and integrated data acquisition programs (Ref. 1–3). Typically, data acquisition focuses on use of a team approach (Ref. 4, 5) as illustrated in Figure 2.
A team approach is also important to achieve data acquisition objectives in mature reservoirs. However, the data acquisition situation may be very different from that of "new" reservoirs. The desire and need for IOR may be critical as the economic limit may be rapidly approaching and data required for IOR may not be available. Smaller reservoir size and lower remaining reserves may present economic constraints towards the acquisition of essential data for the implementation of many IOR methods. The lack of production, fluid properties and other data in the earlier stages of field development may present uncertainties in history matching with numerical simulation methods. This results in unreliable reservoir performance forecasts for IOR. Often, the implementation of data acquisition programs in mature reservoirs present opportunities to enhance near-term reservoir performance through effective reservoir management.
Data acquisition strategies for properties which are being considered for abandonment are not addressed in this paper. Redevelopment of these properties is often required to exploit behind pipe potential and undeveloped zones or horizons.
A Methodology for Prediction of Oil Recovery by Infill Drilling
Authors: Biglarbigi Khosrow , Paul G. W. , Ray R. M. 
Published: December 2007

Abstract
The U.S. Department of Energy (DOE) through Scientific Software-Intercomp (SSI) has developed a predictive model to estimate potential incremental reserves by infill drilling. The Infill Drilling Predictive Model (IDPM) is a three-dimensional (stratified), two-phase (water and oil) model which uses a streamtube simulation approach in calculating incremental recovery by infill drilling from 5-spot waterflood to either 5-spot or 9-spot infill patterns. The IDPM framework is similar to the enhanced oil recovery (EOR) predictive models developed by the National Petroleum Council (NPC) for its 1984 study of U.S. EOR potential. The IDPM has been successfully validated by SSI and independently by the authors using BOAST-II, a three-dimensional, three-phase black oil simulator. Using the IDPM, however, requires knowledge of two important heterogeneity elements which are not easily or often measured in the field. These heterogeneity elements are: (1) pay continuity, and (2) permeability variation among layers.
This paper presents a methodology to approximate pay continuity and permeability variations among layers using the history match of production data. This methodology will facilitate the use of the IDPM in evaluating infill drilling potential in existing waterflood fields. The methodology has been validated against nine actual field case histories.
A Probabilistic Forecasting Method for the Huntley CO2 Projects
Authors: McNutt P. B. , Pittaway K. R. , Rosato R. J. , Beamer R. E. 
Published: December 2007

Abstract
Two words describe our past approach to miscible CO2 economic forecasting: deterministic and optimistic. In order to assess the Huntley CO2 projects more probabilistically and realistically, a team was formed. The team identified five primary areas of risk that are specific to CO2 projects. The team used judgement, experience, and historic information to assign probability distributions to these areas. Monte Carlo simulation was then used to calculate the distribution of economic outcomes. The mean values of the resulting economic indicators were 20% to 36% below the previously calculated deterministic solutions. This paper describes the method that the team developed, the distributions that were used, what risks were excluded and why, and the resources that were used.
Reservoir Management in the Duri Steamflood
Authors: Gael B. T. , Putro E. S. , Masykur Akmal , Lederhos L. J. 
Published: December 2007

Abstract
The Duri Steam Flood (DSF) project has 12 development "Areas" to be processed from now until the year 2021. DSF's development plan uses the following strategies for steam scheduling and reservoir management: inject all patterns and pay intervals evenly at 1.2 BCWEPD/NAF* until steam breakthrough occurs in multiple wells in a pattern, then shift steam out of the breakthrough zones and into the non-breakthrough zones by workovers and adjustments to string injection rates, and finally, after injecting about 1 pore volume steam, reduce rates to heat balance (Vogel1) levels so that by ten years of injection most of the steam capacity can be moved to a new Area. Throughout the project life, producer backpressures are kept as low as feasible. These strategies maximize NPV for the whole project.
Reservoir management in DSF is a life-cycle concept which starts at initial planning/designing of an Area and ends with its abandonment. There are four stages of management for each Area: 1) design and construction, 2) steam ramp-up, 3) a main stage where oil production peaks then progresses to steam breakthrough and requires focus on pattern/layer steam rate optimization and steam rate reduction, and 4) an end-of-project stage where depletion operations are undertaken with due attention given to prevention of inter-Area interference. Reservoir management practices are substantially different depending upon which stage an Area is in.
Injectivity of Sulfonated Polymers Under North Sea Field Conditions
Authors: Noik Christine , Audibert Annie , Delaplace Phillipe 
Published: December 2007

Abstract
Oil field operations for polymer flooding under drastic conditions need suitable commercial products. This study focusses on the flow behavior of suifonated polyacrylamides specially designed to be used under high temperature conditions. The experiments were performed under North sea conditions, i.e. temperature 90°C, seawater brine and North Sea field cores. The main consequences of the introduction of sulfonate units in a polyacrylamide chain are the improvement of thermal stability and shear resistance and a low level of adsorption, with no major problem of retention during core flow.
Closing the Lab-Field Gap: A Look at Near-Wellbore Flow Regimes and Performance of 57 Field Projects
Authors: Smith J. E. 
Published: December 2007

Abstract
The goal of this paper is to link lab and field data in order to resolve a paradox that has caused the shelving of many worthwhile improved oil recovery field projects. Theoretical shear rate calculations often show that polymer or colloidal dispersion gels injected in unfractured reservoirs through perforated completions face certain destruction in terms of shear degradation. Under these conditions, calculated shear rates are often extremely high, and tend to suggest there is no point in injecting polymer, as it will be destroyed to the point of ineffectiveness.
The lab-field paradox is that polymer and colloidal dispersion gels have been injected into these types of reservoirs numerous times and have proven highly successful in spite of high shear rate calculations that suggest otherwise. This paradox represents an important discrepancy between lab/theory and actual field performance. In this paper, lab and field data were combined for 62 injection wells from 57 actual field projects that utilized polymer and in-depth gels. 89% of these projects were successful improved oil recovery floods, yet theoretical shear rates in excess of 50,000 s 1 were calculated for 42% of the injection wells, using basic field assumptions. Although lab data showed that polymer would be destroyed at these high shear rates, the polymer did perform in-situ in all of the injection wells.
Reasons for lab-field discrepancies are proposed and discussed. To determine which field assumptions have the strongest impact on calculated shear rates, sensitivity analyses were performed on several variables. Assumptions for apparent viscosity, injection flux area and permeability have the strongest impacts on results, and are the most poorly defined variables that go into the calculation. This work shows that shear rate calculations for field injection wells should be employed only with a strong knowledge of injection well completions and sensitivities on certain variables.
Improved Sweep Efficiency by Alcohol-Induced Salt Precipitation
Authors: Zhu Tao , Raible Clarence 
Published: December 2007

Abstract
A selective profile modification process was studied to improve volumetric sweep efficiency. This method involved adding alcohol to brine to reduce solubility of salt, which caused the salt to precipitate. For this process, a concentrated brine preflush was injected. This was followed by the injection of a water-soluble alcohol, such as ethanol.
The salt precipitation method has several potential advantages over other profile modification methods such as polymer gels. Profile modification by salt precipitation is not affected by adsorption, and other reservoir conditions, such as, fluid pH and temperature. These are conditions that may affect the gelation process and stability of polymer gels. For applications with CO2 floods, the solid salt is stable to subsequent CO2 flooding. Carbon dioxide flooding can lower the pH of reservoir fluids, a condition which may adversely affect the stability of some polymer gels.
Laboratory experiments indicated that the permeabilities of cores treated by salt precipitation were resistant to subsequent waterfloods with low-salinity brines. Core permeabilities recovered only 5 to 10% of the original permeability after injecting several pore volume of low-salinity brine. Also, corefloods demonstrated the feasibility of the new process to plug high-permeability regions. In parallel coreflooding experiments, the injection of alcohol and NaCl-saturated brine selectively reduced the permeability of highly watered-out cores. Using about 7% PV of reagent grade ethanol for salt precipitation, oil recovery with parallel corefloods of high and low permeabilities was increased by about 20% of the OOIP or about 60% above that of conventional waterflooding. For CO2 coreflooding experiments, the injection of ethanol and NaCl-saturated brine slugs resulted in 12% additional oil recovery of the OOIP or 45% higher oil recovery compared to that of CO2 floods without salt precipitation.
Transactional Environmental Assessments: Use in the Identification of Viable Enhanced Oil Recovery Projects
Authors: Wilson M. J. , Kiser S. C. 
Published: December 2007

ABSTRACT
Environmental site assessments are a valuable tool in assessing the profitability of oil properties with enhanced oil recovery (EOR) opportunities. Industry and government should view the liabilities identified in the environmental site assessment process as research and development opportunities for product development and successful total resource management. The costs to permit, construct, and operate EOR projects within the framework of today's environmental regulations are quantifiable, predictable, and controllable to a certain degree. Knowledge of oil field operations and typical problem areas with the goal of total resource management evaluated in a creative way will help to extend the economic life of the EOR project.
CO2 Foam Field Verification Pilot Test at EVGSAU: Phase IIIA— Surfactant Performance Characterization and Quality Assurance
Authors: Tsau Jyun-Syung , Heller J. P. , Moradi-Araghi Ahmad , Zornes D. R. , Kuehne D. L. 
Published: December 2007

Abstract
This paper is a summary of both new and previous laboratory work done in support of the CO2-foam application in a pilot area of the East Vacuum Grayburg-San Andres Unit (EVGSAU) of southeastern New Mexico. This pilot test was a cooperative effort between the EVGSAU owners, New Mexico PRRC, and the Department of Energy. Different laboratory techniques used for the evaluation of CO2-foam mobility and surfactant adsorption on reservoir rocks are first discussed briefly. Recent results, that concentrate on work with the surfactant selected for use in this field pilot, are then presented. These results display CO2-foam mobility in EVGSAU core samples over wide ranges of surfactant concentration and core permeability. The results generally show a drastically decreased dependence on surfactant concentration above the critical micelle concentration (CMC), and a slightly favorable, but not prominent, dependence of mobility on rock permeability. A further rock sample characteristic pertaining to the initial conditions of the core-from "preserved" through various states of cleaning is also discussed. Additional discussion is given on surfactant adsorption, including results of measurements on Baker Dolomite as well as EVGSAU cores. Using refractometric analysis with the recirculation method, the adsorption results were found to be affected by the water salinity and core conditions. Quality control data for the bulk surfactant and injected solutions, and analyses of the produced brine for tracers and surfactant breakthrough are presented. Foam breakers and emulsion breakers were also evaluated for contingency use in case of the appearance of foam or emulsion in production facilities.
Performance of Morgan Pressure Cycling In-Situ Combustion Project
Authors: Marjerrison D. M. , Fassihi M. R. 
Published: December 2007

ABSTRACT
Amoco Canada has been operating a pressure cycling fireflood at Morgan, in the Lloydminster area of Alberta, Canada, since the mid 1980's. A pressure cycle consists of air injection into a central injector accompanied by production from its surrounding producers. The reservoir contains a 12 API heavy crude and the wells are laid out in 30-acre (12 ha), 7-spot patterns. The rapid drop in the crude oil prices in 1986 led to the successful development and implementation of an innovative pressure cycling-combustion process. This paper looks at the performance of the project and the numerical modelling done to history match the results. The numerical modelling effort was undertaken to explain the high oil rates (individual wells at 120+ STB/D- 19m3/D) and the extraordinarily low injected air-to--produced oil ratio (AOR) of less than 2 MSCF/STB (355 m3/m3). Mechanisms incorporated in the numerical model include: (1) A high speed channel from the injector to the producer, (2) Combustion gas entrainment by the oil phase and (3) Oil upgrading. The physics involved with these mechanisms are explained and the model results are compared with the actual field data. Also, model sensitivities to variations in the assumptions regarding the mechanisms are discussed.
Water-Alternating-Steam Process (WASP) Alleviates Downdip Steam Migration in Cymric Field
Authors: Bautista L. S. , Friedmann Francois 
Published: December 2007

ABSTRACT
The water-alternating-steam process (WASP) was implemented in a one-pattern field trial to control downdip steam breakthrough in a steeply dipping reservoir. The process was implemented because simulation studies of the trial area showed that WASP was technically and economically more effective than conventional rate reductions and foam diverters in correcting downdip steam breakthrough problems.
After two complete cycles, monitoring data was analyzed to determine the technical effectiveness of WASP in reducing reservoir temperatures and in maintaining both reservoir pressure and pattern production. In addition, the economic impact of WASP on thermal efficiency and economics was compared against predicted baseline performance.
Actual field results were also compared to performance predicted from simulation studies to evaluate the effectiveness of simulation in: (1) designing the initial cycle lengths and rates for the WASP field trial, and (2) qualitatively modeling the effect of WASP on the steam zone and project performance.
pH and Reaction Rate Changes During Single-Well Chemical Tracer Tests
Authors: Deans H. A. , Ghosh Rajat 
Published: December 2007

ABSTRACT
The single-well chemical tracer (SWCT) method has been used to measure residual oil saturation to water flooding, (Sor)w, in more than 200 reservoirs since 1968. An essential step in the procedure is the hydrolysis of an ester, the primary tracer, in-situ. At the previous SPE/DOE Symposium4, the variation of hydrolysis rate with pH was claimed to cause serious errors in interpreted (Sor)w in certain cases. This effect has not been accounted for in SWCT test simulator programs, which are used to obtain (SOR)w by matching field measured tracer profiles.
The present work investigates the space-time variation of pH in the formation during a SWCT test. The method employed is simulation, using the chemical flood simulator program UTCHEM. The program was modified to account for the effects of ester hydrolysis reaction products on pH. The hydrolysis rate of ester, already present in the program was modified to depend on pH according to known reaction mechanisms.
UTCHEM was then used to simulate the SWCT test previously reported4 to be effected by pH variations. The shape of the predicted product tracer profiles is indeed changed by the variation of hydrolysis rate with pH. The new tracer profiles come closer to fitting the field-measured results, using a single-layer reversible-flow model. However, the interpreted value of (Sor)w is not significantly changed.
It is recommended that the necessary improvements be added to existing SWCT test simulator programs to account for pH changes. Although this will increase the computing cost of matching field data, the effects may be important enough in some cases to warrant the added complication.
Hydrocarbon Composition and Saturation From Pressure Core Analysis
Authors: Treinen R. J. , Bone R. L. , Vogel H. S. , Rathmell J. J. 
Published: December 2007

ABSTRACTA new method for analyzing pressure cores to obtain quantitative liquid and gaseous phase compositions has been developed. The compositional analysis provides concentration of components including nitrogen, carbon dioxide, and methane through hexatricontanes+ (C36+). Equation of state calculations and material balance data are used to provide saturations of hydrocarbon liquid and gas phases. Previous methods to quantify oil saturation in pressure core samples are based on PVT correlations which are less reliable. Accurate saturations of oil, gas and water in core samples can be obtained with this method even when total hydrocarbon composition changes such as in a gas cap transition zone. The equation of state parameters were obtained by a characterization of PVT data from bottom hole samples.
Application of Combinatorial Algorithms for Description of Reservoir Properties
Authors: Huang XuRi , Keikar M. G. 
Published: December 2007

Abstract
In this study, effectiveness of combinatorial algorithms for describing reservoir properties has been evaluated. Three different types of algorithms: genetic algorithm, simulated annealing, and stochastic hillclimbing method are tested, and the performances of the algorithms are compared through numerical experiments. It was observed that the modified stochastic hillclimbing is the most efficient method for variogram based objective function. The method was also validated by applying it to a case where both variogram and well testing information were available. We concluded that modified stochastic hillclimbing is order of magnitude times faster than the simulated annealing method. The reason for the success of the modified stochastic hillclimbing method is provided through objective function analysis. Finally, the method is applied to a field case to generate interwell porosity distribution.
Mechanistic Study of Carbon Dioxide Flooding Using Horizontal Wells
Authors: Lim M. T. , Pope G. A. , Sepehrnoori Kamy 
Published: December 2007

Abstract
A finite-difference, equation-of-state, compositional simulator has been used to conduct a mechanistic study of carbon dioxide flooding using horizontal wells. We have used the reservoir and fluid properties of an actual West Texas carbonate reservoir that is currently being waterflooded. The phase behavior and properties of the CO2 used in these simulations are typical of those of multiple-contact-miscible (MCM) field conditions of West Texas. Although the equation-of-state MCM calculations require much more computer time, comparison with a first-contact-miscibility (FCM) displacement demonstrates the importance of the more realistic phase behavior description since the injectivity and oil recovery were significantly different for the MCM than for the FCM simulations. All simulations were conducted using permeability fields that have been conditioned with core data taken from two wells in the field. We have compared the performance of the process using a vertical injector and a vertical producer with that using a horizontal injector and a vertical producer combination. We have also investigated the impact of CO2 slug size, skin factor, and relative permeability parameters. These studies show significant sensitivity of the tertiary injectivity of CO2 and brine to the wellbore skin factor and to relative permeability. In tight reservoirs such as that considered in this study, injectivity has a major impact on the efficiency of the process. Although the oil recovery after a given number of injected pore volumes is relatively insensitive to many of the variables investigated in this and earlier studies, the oil recovery at a fixed time such as 20 years varies tremendously since it is limited by the amount of CO2 that can be injected in this time period. This study adds significant new insights and conclusions about the feasibility of using CO2 with horizontal wells.