bluuebunny/crossref_metadata_2025_split huggingface dataset:
Optimization of Surfactant-Based Fluids for Acid Diversion
Authors: Nasr-El-Din H. A. , Al-Nakhli A. , Al-Driweesh S. , Welton T. , Sierra L. , Van Domelen M. 
Published: December 2007

Abstract
This paper examines the use of surfactant gels during acid injection and describes the optimization of these fluids. Unlike available viscoelastic surfactants used today in the field, this surfactant is cationic at low pH values. If used in live acids, the fluid has relatively low viscosity when pumped. However, once the acid is spent the surfactant molecules significantly increase the fluid viscosity. To further enhance diversion, the acidic fluid can also be foamed. Alternately, brine gelled with surfactants can be foamed and utilized for diversion.
Rheological measurements were conducted on Hastelloy fitted rotational viscometers at temperatures from 70 to 300°F. The effects of surfactant concentration and acid additives on the apparent viscosity of various surfactant-based fluids were investigated in detail.
The surfactant was found to be stable and compatible with most acid additives. Some corrosion inhibitors adversely affected the apparent viscosity of surfactant solutions. The apparent viscosity increased with salt concentration. The apparent viscosity of the surfactant solutions can be predicted using Carreau-Yasuda model. Coreflood tests indicated that the surfactant delayed acid breakthrough in carbonate cores. Acceptable corrosion rates were obtained when this surfactant was added to the acid.
The performance of this surfactant was validated with field trials. The surfactant was used in more than fifty field treatments. It was used with up to 28 wt% HCl as in-situ acid diverter. It was also used to enhance the stability and apparent viscosity of foams used for acid diversion in power water injectors.
Constructing Oil Exploration and Development Project Portfolios Using Several Risk Measures—A Realistic Example
Authors: Lasdon L. , Faya L. C. , Lake L. W. , Dyer J. S. , Chen W. 
Published: December 2007

Abstract
This paper describes scenario generators and portfolio models for oil and gas exploration and production (E&P) planning. The problem is how to allocate funds to a set of oil recovery projects to achieve a desired tradeoff between risk and return. A mix of development and exploration projects is assumed, further stratified by reservoir depth and uncertainty level of reserves. The scenario generator incorporates distributions for seven uncertain reservoir parameters, obtained from engineering and geologic data in the Tertiary Oil Recovery Information System (TORIS) database (http://www.netl.doe.gov/scngo/Petroleum/Software/database.html). Capital and operating expenditure data comes from the IHS Energy Discovery Module (www.ihsenergy.com). A slightly compressible-liquid tank model is used to model the yearly oil production from each well in each project. Oil price trajectories are generated using a mean reverting model. A complex income and tax calculation evaluates the net present value (NPV) of free cash flow, and a Monte Carlo simulation generates NPV scenarios for each project.
We describe and compare optimization models that minimize several risk measures, including variance, semivariance, expected loss, and loss probability, as well as models that maximize expected utility. Risk measure values, optimal project weights (assuming any level of fractional participation is allowed in all projects), and portfolio NPV distributions arising from the various risk measures are compared, and contrasted with results of widely used ranking procedures that ignore risk.
Video Microscopy of Methane Gas Production from CBM Coals
Authors: LaReau Brian , Pope John , Buttry Daniel , Lamarre Robert , Noecker Bret , MacDonald Steven , Van Lieu Neil 
Published: December 2007

Abstract
This invention relates a method and apparatus for studying the desorption of gases from coals using optical microscopy. Such desorption reveals the ways in which production of gas from coal occurs under various completion and production scenarios. It can also reveal the efficacy of various stimulation and enhancement methods. The invention discloses methods and apparatus that enable simulation of coalbed reservoirs in a laboratory, and teaches how correlating various analytical techniques with said microscopy can allow researchers to readily evaluate coalbed reservoir properties and production factors.
Optimization of Oil Production Based on A Capacitance Model of Production and Injection Rates
Authors: Liang X. , Weber D. B. , Edgar T. F. , Lake L. W. , Sayarpour M. , Al-Yousef A. 
Published: December 2007

Abstract
This paper presents a methodology to optimize the value of oil produced by adjusting the water injection rates in a mature field.
The reservoir is considered to be a multi-well input-output system with the injection rates as the inputs and production rates as the outputs. A simple capacitance model based on control volume of a given producer is fitted to total injection/production data obtained from a three dimensional reservoir simulator. A power law relationship models the instantaneous water-oil ratio as a function of the cumulative water injected. An optimization problem for oil production is formulated to optimize future performance, where oil production rates and water injection rates are optimized simultaneously based on the selling price of the oil produced and the cost of water injected or the disposal cost of water produced.
The simulation results show that the simple capacitance model satisfactorily captures the long-time behavior between injectors and producers. The solution of the constrained optimization problem for oil production using nonlinear programming can maximize the future economic return of the reservoir asset. Various patterns of optimal injection are followed under different revenue objectives. The optimal injection rates depend on the cost of water injected/disposed, which leads to some wells being shut in while other wells operate at their maximum values.
The proposed optimization method can be used for realtime production control and is appropriate for simultaneous optimization of well rates in a field where injectors are shut-in frequently.
Case History and Appraisal of the West Buffalo Red River Unit High-Pressure Air Injection Project
Authors: Kumar V. K. , Gutierrez D. , Moore R. G. , Mehta S. A. 
Published: December 2007

Abstract
The West Buffalo Red River Unit (WBRRU) project is one of the three High-Pressure Air Injection (HPAI) projects in the Buffalo Field. It produces from the Red River reservoirs, which are deep (~8,400 ft), thin (~15 ft), hot (215 °F), low permeability (~10 md) carbonates. The unit comprising 4,560 acres with 15 producing wells was formed in July 1987 and began air injection operations four months later.
Before unitization the oil production was declining steadily but the response to air injection has resulted in a significant production increase over its historical decline. While unit production in July 1987 was 200 BOPD, a peak production rate of 500 BOPD was achieved in January 1990 with 15 producing wells, after the injection of 2 BSCF of air. As of December 2006 about 23 BSCF of air had been injected, for a cumulative oil production of 2.3 MMSTB since the beginning of injection.
This paper reviews the production and economic performance of the WBRRU high-pressure air injection project to date. The production performance analysis includes estimates of incremental oil recovery due to air injection using conventional decline curve analysis, the expected ultimate recovery using the volume-burned method, and a discussion on how air utilization has changed over time. A detailed economic evaluation is carried out using different economic yardsticks such as net present value and incremental rate of return. A discussion on the impact of oil price on the economic profitability of the project is presented as wells as an estimate of the minimum oil price required for attractive economic results.
To date, the HPAI project in WBRRU continues to be a technical and economic success. In year 2005 old vertical producers were re-entered to drill horizontal laterals and take advantage of the great reservoir response to injection.
Historic Agreement Establishes Training Program for Petroleum Reserves Evaluators
Authors: Black Michael , Olds Dan , Harrell D. Ronald 
Published: December 2007

Abstract
This paper describes the process through which the E&P industry has recognized and acted upon meeting the need for consistent and global training of petroleum engineers and geoscientists responsible for estimating oil and gas reserves. The SPE, AAPG, SPEE and WPC have created "The Joint Committee On Petroleum Reserves Evaluator Training" (JCORET), which is developing a library of training modules that represent industry "best practices". Many, perhaps most, petroleum reserves evaluators worldwide have never participated in training opportunities that truly represent industry-recommended practices.
The sole purpose of JCORET is to develop high quality training modules to be presented and taught to professional reserves evaluators by industry experts at an affordable cost. The program will remain "evergreen" to accommodate new technology and unconventional reservoirs.
Effect of Droplet Size, Emulsifier Concentration, and Acid Volume Fraction on the Rheological Properties and Stability of Emulsified Acids
Authors: Al-Mutairi S. H. , Hill A. D. , Nasr-El-Din H. A. 
Published: December 2007

Abstract
Acid-in-diesel emulsions have been extensively used in matrix acidizing and acid fracturing treatments. This acid has several advantages including lower corrosion rate, minimum number of additives, and deep acid penetration. For stimulation purposes, the most important properties of emulsified acid are reactivity, stability, and viscosity. The size distribution of the droplets of the emulsion affects these properties.
The purpose of this paper is to correlate the droplet size of the dispersed phase (acid) to the viscosity and stability of emulsified acids. Measurements of the droplet size were acquired with laser diffraction techniques and analyzed using an advanced image processing system. Viscosities were measured using Brookfield PVS rheometer at varying temperatures and pressures. The stability of the emulsified acid was monitored using an HTHP see-through cell.
Shear viscosity was measured for emulsions with droplet sizes ranging in diameter from 1 to 20 qm. The viscosity covered a shear rate range from 10 to 750 s−1 and temperature range from 25 to 80 °C. All measurements were regenerated for emulsifier concentrations of 1, 5 and 10 gpt. It is noticed that finer emulsions have higher viscosities. Likewise, similar measurements were performed with varying acid volume fractions.
The most stable emulsion was noted at an acid volume fraction of nearly 0.7. Other volume fractions were stable for a few hours before diesel was expelled as a separate layer above the emulsion. Eventually, the remaining emulsion restabilized at acid volume fraction of 0.7.
This paper discusses the effects of acid volume fraction, emulsifier concentration and droplet size distribution on the rheological properties of emulsified acid.
Productivity Impairment Due to Kaolinite Mobilization: Laboratory and Field Experience, Oseberg Sør
Authors: Fleming Niall , Mathisen Anne-Mette , Eriksen Synnøve H. , Moldrheim Erlend , Johansen Thomas Rudberg 
Published: December 2007

Abstract
Oseberg Sør field, operated by Hydro Oil & Energy, is situated 130km west of the Norwegian coast on the eastern flank of the Viking Graben structure. It consists of fault bounded structural units of varying geological complexity. Within these units the reservoir intervals are of moderate to poor quality and can exhibit strong contrasts in permeability and formation water composition. Reservoir pressure support is provided by combined injection of gas and Utsira aquifer/produced water. The wells are a combination of platform and subsea and include extended reach horizontals with complex geometry and lesser numbers of vertical well.
Coreflooding has been undertaken on material from the major producing intervals (Ness, Middle & Upper Tarbet and Upper Jurassic). This coreflooding has been used to assess potential formation damage resulting from application of oil based mud or scale inhibitor squeeze treatment. In all instances, the major cause of formation damage was the mobilisation of kaolinite that can form up to 20wt% of the bulk rock and occurs in all producing intervals. Coreflooding demonstrated that even at very low flow rates (30ml/h) permeability was reduced by up to 99% during initial plug saturation and before the onset of treatment. Modification of the coreholder allowed multi-port permeability measurements to be made that gave an indication of the depth of damage.
Field evidence only gives an indirect indication of the effect of kaolinite mobilization on well productivity. For example, a gradual reduction in well productivity has reversed after squeeze treatment. This gradual decline is possibly a result of the migration of kaolinite during well inflow with consequent reduction in permeability. Squeezing could have caused the dispersion of kaolinite away from the near wellbore with an increase in well productivity.
Given the adverse results obtained from coreflooding due to kaolinite mobilization, significant effort has been directed towards identify methods by which to reduce its impact, through incorporation of clay stabilizers in scale inhibitor squeeze treatments and remedial treatments using mud acid stimulation. Laboratory results of these evaluations will be presented (mud acid coreflooding results were not available at the time of writing).
While the occurrence of kaolinite on Oseberg Sør has potentially reduced well inflow performance, it has had a positive influence on scale inhibitor squeeze lifetimes. A field example will be given to show this.
Acid Stimulation of Extended Reach Wells: Lessons Learnt From N'Kossa Field
Authors: Mazel J. M. , Poitrenaud H. , M'Bouyou P. 
Published: December 2007

Abstract
N'Kossa is an offshore field located 60 km west of the coasts of Congo in water depths of 170 m. The field is producing light sweet oil from an Albian age reservoir buried between 3100m and 3400m TVD. In order to access reserves located in the southernmost compartments of the reservoir, Extended Reach Drilling (ERD) was implemented. Six ERD wells have been drilled to date with lateral extensions close to 6500 m leading to total depths sometimes in excess of 8600m. In addition to the challenges pertaining to the drilling itself, the completion also carried its own ones as the formation would require effective acid-stimulation (not only an acid wash) to reach the desired levels of productivity. Stimulation of long intervals, and how to ensure full coverage of treatments is a recurrent topic of debate, several approaches have been discussed in the literature. In the particular case of N'Kossa, this issue was not only rendered difficult by the length of the perforated intervals (up to 1200m) but also derived from the combination of lithology and permeability contrasts existing in the formation: indeed the reservoir is an alternation of rather tight carbonates (with permeabilities as low as 1 mD) and porous sandstones (which permabilities sometimes reach up to 400mD). The contrast in permeability is unfavorable as the high permeability layers are often encountered at the heel of the drains. Finally, the reservoir temperature is 150°C (300°F), leading to the need for retarded acid systems.
Building on the experience acquired from the successive treatments performed on N'Kossa, the methodology and treatment design, fluids and diversion have been continuously evolved. The treatments currently involves two phases: An injectivity initiation is performed via Coiled-Tubing creating an artificial thief zone at the toe of the well; then a massive treatment based on emulsified acid and ball-sealer diversion is bullheaded from a stimulation vessel.
This paper will discuss design considerations and operational aspects of the acid treatments performed of these ERD wells. We will discuss some of the observations made and present lessons learnt from such treatments.
Laboratory Assessment of Drilling-Fluid Formation Damage in Sandstone Cores and Mitigation With Lignite Additives for High-Temperature Fields
Authors: Kelessidis V. C. , Marinakis D. , Tsamantaki C. 
Published: December 2007

Abstract
This paper describes first results of an extensive laboratory research program aiming at identifying potential additives for bentonite suspensions which would extend their use at high temperatures by maintaining or even improving the rheological and the filtration characteristics of these fluids.
Five different Grrek lignites have been tested, at 3% wt. concentration, together with a commercial lignite product, used as reference. API filter press data and rheological data showed that thermal aging of bentonite suspensions results in deterioration of rheological and filtration properties while lignite addition was very beneficial.
Static filtrations tests against Berea sandstones have been performed using a core holder and the various mud formulations. Pressure ports along the core holder allowed determination of permeability evolution during testing of the formed cake as well as of the core itself. A backflash arrangement allowed for determination of permeability recovery.
Thermally aged muds reduced significantly core permeability and gave recovery rates around 50%. Three of the lignite samples, have maintained original core permeability giving also very high recovery rates. Some of the lignite samples, including the commercial one, did not perform as well and also gave permeability recoveries between 10 to 80%. Thus, static filtration against cores allows for differentiation of well performing lignite samples not only in API filter press tests but also in core permeability experiments.
Robust Recovery of the Filtration Function for Flow of Water With Particles in Porous Media
Authors: Alvarez Amaury Cruz , Hime Gustavo , Marchesin Dan , Bedrikovetsky Pavel 
Published: December 2007

Abstract
Models for deep bed filtration during the injection of seawater with solid inclusions depend on an empirical filtration function that represents the rate of particle retention. This function must be calculated indirectly from experimental measurements of other quantities. The practical petroleum engineering purpose is to predict injectivity loss in the porous rock around wells. This phenomenon is studied in laboratory injection tests, where the effluent particle concentration is measured over time.
We presented in a previous work1 a method for determining the filtration function from these measurements. In this work, we improve on this method introducing a data preprocessing technique which makes the algorithm robust, and present numerical results with data which could not be treated before. The main purpose of this paper is to present this complete method for the solution of the inverse problem of determining the filtration function in the classical deep bed filtration theory from injected and effluent particle concentration measurements.
Modeling and CT-Scan Study of the Effect of Core Heterogeneity on Foam Flow for Acid Diversion
Authors: Farshbaf Zinati F. , Farajzadeh R. , Zitha P. L. J. 
Published: December 2007

Abstract
We present a new 2D analysis based on the recently developed stochastic bubble population foam model, focusing on the effect of the core heterogeneity. In the frame of the model presented in a parent paper in the conference, we assume that the bubble generation kinetics is dependent on layer permeability. We present experiments consisting of co-injection of N2 gas and surfactant solution in layered cores, with layering parallel and to the flow directions. The cores are obtained by combining two porous media chosen from Benteimer and Berea sandstone and sintered glass, with large permeability contrast. X-ray computed tomography (CT) scans are used to visualize and quantify local fluid distributions and differentiate foam propagation in the different layers. From both the model and the experiments we conclude that foam is primarily generated in the high-permeability layers, where it propagates at a much higher speed than in the low permeability layer. The propagation of foam in the low permeability layer requires that the pressure gradient is higher than the capillary entry pressure for the layer. The new stochastic population balance foam model reproduces rather well the main features of foam motion in heterogeneous cores containing a surfactant. Core floods combined with CT scan imaging provide valuable specific information about the effect of heterogeneity for better design of acid diversion operations.
Optimizer's Curse: Removing the Effect of this Bias in Portfolio Planning
Authors: Schuyler John , Nieman Timothy 
Published: December 2007

Abstract
Even with unbiased judgments and project calculations, an insidious bias will still be present in an approved projects portfolio. The screening and ranking process used to select projects causes an optimizer's curse effect (Smith and Winkler, 2006). A portfolio's true outcome value will tend to fall below the forecast distribution mean. Stated another way, we should expect to be disappointed in the value of the eventual outcomes. This optimizer's curse effect can be huge: the true portfolio value might be half its forecast value when forecast in the usual way.
This paper describes a correction process based upon Bayesian inversion obtained with Monte Carlo simulation. Estimate/Actual distributions characterize component evaluation errors. The mean and standard deviation of the E/A distribution measures the quality of judgments and estimates. Examples demonstrate the value of better information in project or asset evaluation, portfolio optimization, and competitive bidding.
The premise of our approach to correct for optimizer's curse is straightforward enough, though implementing this method requires judging the population of evaluated projects—or at least assessing the shape of this population's distribution. We offer a process and guidelines for correcting for the optimizer's curse in both project and portfolio value calculations. Correcting estimates for systematic biases restores luster to the recommended expected value-maximizing decision policy. We also tie-back to the winner's curse (Capen, Clapp and Campbell, 1971) experienced in competitive bidding and how it affects bid optimization.