bluuebunny/crossref_metadata_2025_split huggingface dataset:
Optimizing Waterflood Recovery in a Mature Waterflood, The Fullerton Clearfork Unit
Authors: Stiles L.H. 
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers Inc.

Abstract
After a detailed study of 12 years' performance of the Fullerton Clearfork performance of the Fullerton Clearfork Unit, a special study group recommended major operating changes which will increase ultimate oil recovery 22 million barrels. New techniques included a simplified waterflood model and a statistical approach to measure reservoir continuity. Evaluation of alternate plans with these tools indicated the plans with these tools indicated the need for infill drilling and a closer spaced pattern.

Introduction

Location and Geology
The Fullerton Field is located in west Texas in Andrews County, 50 miles north-west of Midland as shown on Figure 1. Geologically, the field is located in the northeastern part of the Central Basin Platform Area, and lies in a north-west-southeast trend of Permian carbonate production stretching for more than 100 miles. Figure 2 is a structure map which shows the northwest-southeast trending, anticline with approximately 400 feet of relief on top of the Clearfork formation. There are two prominent structural domes on this feature with the North Dome being much the larger of the two. The Fullerton structure continues northward from the Unit boundary and is productive in the adjacent, but separately prorated Union Field. Discovery was in 1942 and was followed by rapid development during the next five years with 565 wells completed by 1947. Development continued throughout the 1950's and 1960's with sporadic development up to the present time.
Preparation and Testing of Partially Hydrolyzed Polyacrylamide Solutions
Authors: Foshee W.C. , Jennings R.R. , West T.J. 
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers Inc.

Abstract
The evaluation of a mobility control polymer requires; that proper laboratory techniques be followed if meaningful results are to be obtained. New procedures are presented and existing procedures are reviewed to aid in the procedures are reviewed to aid in the measurement of properties related to performance of polyacrylamide solutions. In addition to polyacrylamide solutions. In addition to mixing and filtration techniques, the measurement of polymer concentration, thermal stability, core testing, and other factors relating to mobility control in the reservoir are discussed.

Introduction
Polymers are being widely used to provide Polymers are being widely used to provide mobility control in secondary and tertiary oil recovery processes. Large quantities of polymer are required for these processes and it is imperative that adequate, but not excessive, quantities be used to insure the economic success of these processes. To accomplish this, it is necessary that sufficiently accurate laboratory core data be developed to permit optimum mobility bank design.
This paper will describe the elements of such a laboratory testing program. It will be organized into three sections:Solution PreparationCharacterization of Polyacrylamide Solutions.Polyacrylamide Behavior in Field Core Specimens
In Section I, procedures will be given to dissolve polymers properly in stable analogs of the natural field brines. Section II continues with methods to assess the properties (screen factor viscosity and thermal stability) of polyacrylamide dissolved in brine. It also contains polyacrylamide dissolved in brine. It also contains a new analytical method to determine the polymer concentrations in oil field brine. The last section describes tie techniques used to measure polymer solution behavior in actual field core specimens.
The procedures presented are the results of hundreds of core tests using water soluble polymers. Although this paper is not a polymers. Although this paper is not a complete reference manual, an attempt has been made to cover many of the critical points. A topical sentence has been underlined to identify recommended standard procedures in Section I and in Section II where alternative procedures are also discussed. It is hoped that the procedures are also discussed. It is hoped that the methods presented might be considered as the first step in setting standards for resistance factor determinations.
Historical Problems with Old Field Rejunvenation
Authors: Blaskovich F. T. 
Published: December 2007

Abstract
In many parts of the world, the redevelopment of older fields presents unique problems that will require innovative solutions. With the rising costs of finding and developing new oil fields, oil companies are turning more attention to revitalizing existing fields. Because of historical practices, these fields often have significant potential for enhanced recovery. These older fields have many different problems to deal with than the more modern fields that traditionally drive petroleum technology.
Advances in computer hardware and software technology have made it possible to analyze reservoirs at a level of detail unimagined only a few years ago. With all of this power on our desktops, it is easy to lose sight of a major problem in dealing with older fields - the historical data.
In many cases, there may be a large amount of historical data, but much of it is either inaccurate or critical types of data have not been gathered. Several field examples are discussed in this paper. Each field has redevelopment potential using modern techniques, but each project has great uncertainty due to data constraints. The conclusions and recommendations of the paper include suggestions for ways to solve these problems. Since we cannot go back in time to gather critical missing data (e.g., early production and injection data, initial fluid properties, produced compositions, etc.), special techniques will be needed to determine the value of these projects.
Application of a Point the Bit Rotary Steerable System in Directional Drilling Prototype Well-bore Profiles
Authors: Schaaf Stuart , Pafitis Demos , Guichemerre Eric 
Published: December 2007

Abstract
Recent trends in the oil industry are requiring higher degrees of accuracy in the placement of boreholes, while improving overall rates of penetration. In addition to reducing overall drilling costs, several technical reasons can be cited. These include: Increasingly complex directional well trajectories designed to drain more of the reservoir; accurate build rates and precise landing of horizontal wells; accurate horizontal control for steering relative to an interface or to reduce undulation in extended reach wells.
Rotary steerable systems have been introduced in the past few years to respond to these more complex requirements. These systems have shown the potential for reducing the costs of drilling while providing improved directional control. Elimination of sliding increases rates of penetration, provides better hole cleaning, smoother boreholes, less chance of differential sticking; and the ability to drill further. Schlumberger has developed a new rotary steerable system, which functions on a point-the-bit principle. The system has no non-rotating or stationary parts in contact with the formation. The system is implemented in a 6 ¾-inch platform and operates in bore-hole diameters between 8 3/8-inch and 9 7/8-inch.
This paper will present an overview of the new point-the-bit system. Benefits of the system will be discussed. Case studies from two wells will be presented. The presentation will discuss the well objectives, the plan implementation, and include operational highlights and issues. Project results and improvements in implementation will be presented with discussion on how the system was utilized to insure value-added savings.
Comprehensive Reservoir Modeling of a Mature, Geologically Complex Reservoir
Authors: Pawar RJ , Edwards EB , Coombs SF , Whitney EM 
Published: December 2007

Abstract
The Carpinteria Offshore field in the Santa Barbara channel is a geologically complex, mature reservoir. Over the past years production has declined due to increased water cut and sand production from unconsolidated zones. The current operator of the field, Pacific Operators Offshore Inc. (POOI), a small and independent producer joined with Los Alamos National Laboratory in a joint research program. The purpose of the program was to use advanced computational tools to improve understanding of the field geology and fluid dynamics. No comprehensive model of the field was available prior to this project. As part of the project, a geologic model that integrated the legacy data was developed. The model was used to develop a reservoir flow simulation model for a part of the field. The model was used to qualitatively understand field fluid dynamics. Subsequently, geostatistical techniques were used to characterize the spatial heterogeneity in reservoir rock properties. Multiple realizations were generated for individual rock properties and the uncertainties associated with the property distributions were quantified. The geologic model has been extensively used by POOI during planning stages of a field redevelopment program. The newly drilled wells have dramatically increased the production from the field. The increased production has been tremendously helpful for the company during the recent oil production shortage.
Detailed Clastic Maps from Intense Log Data Extractions and Advanced Sedimentation Analysis
Authors: Allen Rob L. 
Published: December 2007

Abstract
Major changes were made to conventional mapping procedures. Hundreds of map input values are usually extracted from an interval of interest on each log instead of using an averaged sand thicknesses or a few other properties. Reversible wave, current, gravity, partial derivative, and particle dispersion mathematics are used to model sedimentation processes. Log pattern inversions combined with the above sedimentation emulation technologies have been used to create much more detailed maps of depositional systems.
Implementation of Fracture Calibration Equations for Pressure Dependent Leakoff
Authors: Meyer Bruce R. , Jacot R. Henry 
Published: December 2007

Abstract
Nolte originally developed a pressure decline analysis method to provide an estimate of the fluid efficiency, closure pressure, fracture geometry and leakoff coefficient. The Nolte method of pressure decline analysis has become a standard for fracture calibration in the industry. Implementation of a proper calibration test is critical for the successful design and evaluation of hydraulic fracturing treatments.
Although Nolte's original work has many simplifying assumptions regarding fracture closure (e.g., constant leakoff coefficient, no spurt, no fracture growth after shut-in, constant compliance, etc.) it still provides the foundation for the basic first order parameters affecting pressure decline behavior.
The assumption of pressure independent fluid loss may have an adverse affect on the pressure decline analysis if leakoff is controlled by the filtrate viscosity and/or reservoir compressibility and mobility effects or fissure opening effects. An improved procedure is presented for identifying and implementing pressure dependent leakoff. This methodology is formulated from the generalized Nolte G function approach utilizing a dimensionless pressure function based on the original work of Castillo for a pressure dependent leakoff coefficient and Barree for naturally fractured reservoirs. The procedure first makes use of the standard Nolte analysis to identify the presence of pressure dependent leakoff, and then establishes the appropriate leak-off pressure dependent parameters by matching the pressure decline behavior. Deviation of the measured data from the dimensionless pressure function versus Nolte G time indicates closure. The methodology also utilizes the first derivative and pressure superposition derivative to help identify and quantify closure.
Guidelines are presented to identify cases where pressure dependent leakoff should be considered. Implications of neglecting pressure dependent leakoff or using a pressure dependent leakoff coefficient improperly are addressed. The governing equations and field examples are presented for clarity.
Characterization of Spontaneous Water Imbibition into Gas-Saturated Rocks
Authors: Li Kewen , Horne Roland N. 
Published: December 2007

Abstract
Spontaneous water imbibition into gas-saturated rocks is an important physical process during water injection into highly fractured petroleum and geothermal reservoirs. Few methods, however, are available for characterizing the process of spontaneous water imbibition into gas-saturated rocks. To this end, a method has been developed. Water relative permeability and capillary pressure can be calculated separately from water imbibition data using this method. A linear relationship between imbibition rate and the reciprocal of the gas recovery by spontaneous water imbibition was found and confirmed both theoretically and experimentally, even at different initial water saturations. The effect of initial water saturation on imbibition rate, residual gas saturation, and the gas recovery has been investigated. There was almost no effect of initial water saturation on residual gas saturation by spontaneous water imbibition. The higher the initial water saturation, the lower the water imbibition rate and the ultimate gas recovery. It was found that the capillary pressure did not vary with initial water saturation in a certain range. The capillary pressure calculated using the new method was approximately equal to the values measured using an X-ray CT technique in a glass-bead pack. The computed water relative permeability was consistent with published experimental results. The method developed in this paper is also of importance for scaling-up experimental data.
Approximate Finite Difference Modeling of the Performance of Horizontal Wells in Heterogeneous Reservoirs
Authors: Yeten Burak , Wolfsteiner Christian , Durlofsky Louis J. , Aziz Khalid 
Published: December 2007

Abstract
A simplified representation of reservoir heterogeneity is applied to the finite difference modeling of horizontal wells operating under two phase flow conditions. The heterogeneity model, referred to as the s-k* approach, was developed and applied in earlier studies for single phase flow scenarios. The model represents heterogeneous permeability fields in terms of a constant background permeability k* and a variable skin s, which captures the effects of near-well heterogeneity. This simplified permeability representation is applied to the modeling of multiple realizations of heterogeneous permeability fields characterized by three different sets of permeability statistics. Comparisons to simulation results using the detailed permeability field and to results using a homogeneous permeability field are presented. The s-k* permeability representation is shown to provide an accurate means of representing reservoir heterogeneity in models of horizontal well performance. Integrated quantities, such as well productivity index, are captured with better accuracy than are more local quantities such as water cut. The s-k* models are more accurate than the homogeneous models in all cases considered. The use of the new modeling approach for the coarse scale modeling of horizontal well performance is also demonstrated.
An Experimental Investigation of Permeability and Porosity Alteration in Diatomite During Hot Fluid Injection
Authors: Kovscek A. R. , Diabira I. , Castanier L. M. 
Published: December 2007

Abstract
A study of silica dissolution has been performed to probe the evolution of permeability and porosity in siliceous diatomite during hot fluid injection, such as water or steam flooding. Two competing mechanisms were identified. Silica is soluble in water at elevated temperature causing rock dissolution and thereby increasing permeability; however, the rock is significantly compressible leading to compaction of the solid matrix during injection and the loss of permeability and porosity. A laboratory flow apparatus was designed and built to examine these processes in diatomite core samples. At the core level, we measured the pressure drop as a function of time to determine the permeability variation and utilized an X-ray Computerized Tomography (CT) scanner to measure porosity. At the pore level, a scanning electron microscope (SEM) was used to observe changes in pore morphology. We found that porosity decreased initially due to compaction caused by the imposed pressure drop across the core. Later, porosity increased as silica dissolved. Dissolution of the rock matrix was relatively uniform in that wormholes were not observed even after tens of pore volumes of fluid injection.
Burst Induced Stresses in Cemented Wellbores
Authors: Fleckenstein W. W. , Eustes A. W. , Miller M. G. 
Published: December 2007

Abstract
The industry acknowledges that there is an increase in the burst resistance of cemented pipe vs. uncemented pipe; but the effects of cement and formation mechanical properties, and insitu stresses are not well understood. This paper presents the results of a finite element study of the resistance of casing to internal burst pressure under a variety of conditions. This will provide for better design understanding of the stress conditions developed in casing under burst loading.
Two-dimensional stress distribution model results are presented in graphical and tabular format for a variety of geometrical and mechanical material properties of formations, cement slurries, and casing combinations.
A better understanding of the true stress profile in cemented pipe will allow for less expensive decisions concerning casing design parameters and safety factor criteria. Applications of using the burst resistance of the cemented pipe as a system as opposed to using the burst resistance of free pipe can include deeper drilling with thinner walled pipe, smaller rigs, and better casing integrity decisions for refracturing candidates.
Vertical Permeability from In-Situ Horizontal Permeability Measurement in Shaly Sand Reservoirs
Authors: Zahaf K. , Tiab D. 
Published: December 2007

ABSTRACT
The oil industry has become more and more aware that reservoirs exhibit complex variations of reservoir continuity, in particular of pore space-related properties such as porosity, permeability, and capillary pressure. These variations reflect the original depositional process and subsequent diagenetic and tectonic changes. Simple models are often inadequate for predicting reservoir performance and designing a field production management scheme that optimizes recovery. It is becoming increasingly apparent to reservoir engineers that the optimization of recovery is crucially dependent on the quality of the reservoir under water injection where the recovery factor is very sensitive to reservoir heterogeneity. Therefore, an accurate knowledge of vertical and lateral permeability distribution is essential.
This paper represents results of a research project aimed at determining vertical permeability from in-situ horizontal permeability in shaly reservoirs. This is accomplished by considering the microscopic and macroscopic features; such as the type of shale (Kaolinite, Chlorite, and Illite) and grain size. In-situ vertical permeability correlations are derived by using various water saturation correlations for Shaly-Sand formation.
Several vertical permeability relationships were obtained as function of horizontal permeability, hydraulic mean radius grain size, and the amount and/or type of shale. Generalized models were developed and were applied to real oil field data for calculating vertical and horizontal permeabilities.
The Top 10 Reasons to Rethink Hydraulics and Rheology
Authors: Zamora M. , Roy S. 
Published: December 2007

Abstract
After a century of need, the drilling industry finally has the tools to properly analyze and optimize drilling fluid hydraulics. This is indeed fortunate, because most unscheduled trouble events in drilling are still hydraulics related. Emerging results from these tools and recurring field problems and challenges provide many good reasons to rethink drilling hydraulics and rheology, especially in critical-well applications. This paper is about the reasons that made the Top 10 list.
Real-time downhole pressure measurements, powerful / inexpensive computers, and quality HTHP / LT viscometers are among the most notable new diagnostic tools. Individually and collectively, they continue to remind the industry, for example, that downhole mud properties are different than those measured under surface conditions. Failure to compensate for significant differences in density, rheology, pressure loss, and other parameters can cause great difficulties, especially in wells drilled in HTHP and deepwater environments.
Items in this Top 10 list cover a wide range of hydraulics and rheological issues. Some focus on specific well conditions, some address new findings, and others dispel long-standing oilfield paradigms. All are practical and useful for solving common and unique well problems. Field examples are given where appropriate.
Experiments in Fluid Loss and Formation Damage with Xanthan-Based Fluids While Drilling
Authors: Navarrete R. C. , Dearing H. L. , Constien V. G. , Marsaglia K. M. , Seheult J. M. , Rodgers P. E. 
Published: December 2007

Abstract
Formation damage is a concern when attempting to control fluid loss during drilling operations. The usual approach is to use bridging agents and high polymer loadings to reduce fluid loss. However, these additives contribute to formation damage. In this paper we explore the fluid loss characteristics of xanthan-based fluids, including starch and calcium carbonate, during the drilling process. Fluid loss while drilling is a complex process where fluid is lost underneath the bit and through the surface of the wellbore. A unique laboratory scale drilling simulator was used to determine the leakoff and formation damage of xanthan-based drilling fluid formulations. The fluid was circulated as in a conventional drilling operation, through the microbit and up the annulus under overbalanced conditions. Thin section analysis and environmental SEM were performed on rock samples to identify the different components of the fluid system. Sandstones up to 1,000 md were used. Cleanup sequences, which include enzymes and oxidizers, were also evaluated after the cores were drilled. The cleanup efficiencies were compared to conventional QC-testing techniques used by operators for filtercake removal.
The results showed that most of the fluid is lost underneath the bit in a continuous spurt condition while drilling. The filtercake formed during drilling does not pose a resistance to flow during production, but poses a strong resistance during leakoff. Xanthan gum contributes to fluid loss reduction, while combinations of CaCO3, starch and xanthan gave the lowest leakoff and formation damage. Wellbore soaking procedures do improve production after drilling.
Marvelous Effect of Magnetization on Drilling Fluid
Authors: Gao Changhong 
Published: December 2007

Abstract
Magnetic technology has been widely used in oil fields and other aspects due to its many outstanding advantages. Yet its main utilization lies in oil production and transportation, and little research is done on the magnetized drilling fluid. In this paper, through experiment, it is shown that magnetization can apparently reduce the viscosity and improve the inhibition ability of the mud system.