bluuebunny/crossref_metadata_2025_split huggingface dataset:
Low-Cost Alternative for Remedial Sand Control Application
Authors: Peavy M. A. , Bush M. E. , Plummer M. A. , Perez J. I. 
Published: December 2007

Summary
During mid-1992, a remedial workover program was implemented offshore within the Gulf of Mexico on low-rate marginal-reserve sand-producing wellbores. A process called through-tubing gravel packing (TTGP) was used on five offshore wells and one U.S. gulf coast land well. This technique involved the placement of ceramic beads and prepacked screen within existing completions with coiled tubing (CT) to eliminate sand production (Fig. 1). The basic steps of TTGP consist of wellbore cleanup, CT counter correlation, injectivity testing, running a dummy assembly, ceramic bead placement, prepacked screen placement, and installation of an isolation device. The TTGP method demonstrated versatility in adapting to individual well conditions. This remedial sand control technique was successfully applied in highly deviated wellbores, in the upper zones of a dual completion, and within existing gravel packs for screen repair.
TTGP's were performed offshore in as little as 5 days with a CT unit at a cost of $63,500. Five wells were mechanically successful, but only three wells were considered economic successes. Simple individual payouts for the wells ranged from 46 to 77 days, with an associated production gain of 2,020 Mcf/D and 39 BOPD. Economic success improved over time as mechanical success increased. Project incremental production was 1,070 Mcf/D and 38 BOPD. The total cost of the project was $571,807. The average offshore workover cost was $ 110,761, and the workover cost for the onshore well was $18,000.
Throughout the implementation of this program, mechanical problems were addressed that led to improvements in subsequent workover programs. This paper details the TTGP program and recommends mechanical improvements for performing future through-tubing gravel packs.
Criteria for Sizing Multiphase Flowlines for Erosive/Corrosive Service
Authors: Svedeman S. J. , Arnold K. E. 
Published: December 2007

Summary
API RP 14E provides no specific guidelines for the design of multiphase pipelines for corrosive and erosive service. This paper presents criteria for determining appropriate pipe sizes for clean service and for service where corrosive fluids or solids production are present.
Development of a Matrix-Acidizing Stimulation Treatment Evaluation and Recording System
Authors: Montgomery C. T. , Jan Y.-M. , Niemeyer B. L. 
Published: December 2007

SummaryWhen compared with hydraulic fracturing, matrix stimulation has a very high failure rate. This paper describes the development and field testing of a matrix-stimulation field-monitoring system designed to provide real-time control, optimization, and postjob evaluation of matrix treatments. Using calculated bottomhole pressures (BHP) or coil-tubing/tubing-annulus reflected pressures, the system predicts pretreatment damage or skin from a step-rate test, then shows the evolution of skin removal vs. treating fluid volume or time. The system-provides real-time information to the operator conducting the treatment about when to drop diverter, treating fluid efficiency, and diverter efficiency. The system can also be used to estimate treatment height and damage radius. Input data can come directly from the service company's digital sensors or from separate sensors placed in the treating line. A description of the system and several case histories showing its utility are presented.
A New Method for Direct Measurement of In-Situ Stress Directions and Formation Rock Properties
Authors: Lin Peng , Ray Tommy G. 
Published: December 2007

Summary
This paper presents a new method to determine in-situ stress directions and in-situ formation rock properties with a newly developed downhole extensometer. The extensometer is used to measure wellbore deformation, pressure, and temperature during a microfracture stress test. This paper presents the method used to analyze the data this new device collects. Some of the parameters that can be determined are (1) principal stress directions, determined from the induced fracture orientation; (2) minimum in-situ stress magnitude, determined from the fracture width calculations and the conventional microfracture analysis; and (3) in-situ static rock properties, determined from the prefracture wellbore deformation. This paper emphasizes the theoretical methodology used in the data analysis. A field case example is included.

Introduction
Many production problems-including drilling and wellbore stability, fracturing (for vertical, deviated, or horizontal wells), sand production, and casing failure-require knowledge of the in-situ stress magnitudes and directions, and such in-situ rock properties as Young's modulus, shear modulus, and Poisson's ratio.
Present ways of determining the fracture/in-situ stress orientation at great depths involve either testing of recovered oriented cores [e.g., an elastic strain relaxation, (ASR)] or microfracture tests during drilling and subsequent recovery of the oriented fractured core. A widely accepted method of determining closure pressure (minimum in-situ stress) is microfracture analysis. This type of analysis relies on the pressure-decline data to match a particular model.
Several techniques, static and dynamic, exist for determining rock properties. Static methods usually involve laboratory tests that require carefully prepared samples and often are time-consuming. In addition, retrieved samples are no longer in the in-situ state, and the samples usually are very small compared with the formation being studied. On the other hand, dynamic methods, such as sonic logs, are based essentially on rapidly applied, nondestructive loads. They usually are performed under in-situ conditions. However, statically determined parameters are preferred in hydraulic fracture design because they represent actual loading conditions better.
New Polymer Technology for Water Control in Gas Wells
Authors: Dovan H. T. , Hutchins R. D. 
Published: December 2007

Summary
A new polymer treatment process has been developed for selectively reducing water permeability in gas wells. Three field treatments are discussed. The most notable treatment was performed on an offshore gas well that previously was loaded up with water. The treatment returned gas production to the well, averaging 1.9 MMcf/D gas for almost 3 years. The water production was reduced from a high of almost 600 to &lt; 50 B/D. The treatment was performed in 1 day using common oil- and gas-field acidizing equipment. The treatment design was based on information from earlier field treatments, laboratory corefloods, and gel screening data.
Incident Investigation and Analysis for Exploration and Production Operations
Authors: Waterfall K.W. , Milne D.J. 
Published: December 2007

Summary
Incident investigation and analysis in Shell E&P operations is part of performance monitoring in health, safety, and environment (HSE) management systems. The focus is on identifying underlying causes. A step-wise approach is given from immediate response through determining the level of investigation, coverage of investigation aspects, analysis, recording, and follow-up. The means to analyze incidents by application of the Tripod system, which is directed toward understanding underlying causes of incidents, are reviewed.

Introduction
HSE performance monitoring has been, and in some areas still is, based on reactive statistical indicators that can identify at best only that past decisions have resulted in unsatisfactory conditions or work climates. To understand how to improve HSE performance and which managerial aspects have to be changed, it is essential to have a meaningful system for assessing the underlying causes of incidents. The system needs to address not only accidents, where there is a measurable impact resulting from failures, but also situations where no adverse consequences occurred but the potential for loss or damage existed. To make a lasting effect on incident reduction requires a timely, balanced, and consistent approach to "blame-free" investigation of all incidents, identification of underlying factors, and correction of systemic causes.
This paper addresses incident investigation and analysis as part of a structured approach to performance monitoring in HSE management systems. Incident investigation forms an essential part of the feedback loop in an ISO 9000 application to company management and is consistent with recent guidance issued by the U.K. Health & Safety Executive. In addition, we discuss the need to develop and use proactive monitoring systems and indicators.
In 1993, Shell IntI. Petroleum Mij. produced a revised guidance document for Shell E&P operating companies. This paper addresses the changing approach to incident investigation in the E&P industry. The terms "accident" and "incident" have specific definitions in the context of this paper (see the Appendix).
Using a Physical Wellbore Model To Study Formation Damage Problems in Well Completions
Authors: Burnett D. B. 
Published: December 2007

Abstract
This paper describes the design and operation of a high pressure, high temperature wellbore model using either consolidated or unconsolidated core material. It can be configured with up to eight perforated cores representing varied zonal permeability. The model is set up for flow in either the injection or the production direction. It is acid rated and fluids can be pumped at rates to 130 BPD. Gravel-packing is accomplished in the model with either water or polymer carrier fluids.
The model is used to perform laboratory evaluations of completion practices and stimulation techniques. We have evaluated the formation damaging potential of commonly used loss circulation materials and the inability to clean up some of these materials in unconsolidated formations. We have used the model to demonstrate the benefits of gravel pre-packing to avoid loss in perforation flow capacity. We have also evaluated diverting agents designed to improve coverage and stimulation of damaged zones.
Fluosilicate Solubilities Affect HF Acid Compositions
Authors: Gdanski R. D. 
Published: December 2007

Summary
The purpose of this work was to determine the solubilities of sodium and potassium fluosilicate over a broad range of HCl concentrations, ionic strengths, and temperatures. These data were required for determining optimum or safe HCl/HF treating-fluid compositions for acidizing sandstone formations containing feldspars. Solubilities of sodium and potassium fluosilicate were determined over a temperature range of 150 to 300°F. Analysis of the solubility data indicated that the solids formed were not simply Na2SiF6 and K2SiF6. Regression analyses indicated that the sodium salt could best be described as NaHSiF6 · 0.52HCl (or Na0.48H1.52SiF60.52NaCl). Regression analyses indicated that the potassium salt could best be described as KHSiF6 · 0.41KCl (or K1.41H0.59SiF6· 0.41 HCl). The solubility data were then included in a HF-spending simulator to determine regions where possible precipitation of the fluosilicates could occur. Optimum HCl/HF concentrations were then determined for specific mineral and temperature conditions.
A New Technique for Evaluating Field Cement Mixing
Authors: Benge Glen 
Published: December 2007

AbstractCement service companies have developed spacer systems to address various flow regimes, developed a wide array of mixing equipment and have written computer simulation programs to address a wide range of well parameters. Most of the simulation programs evaluate hole geometry, wash uts, eccentered casing, and U-tube effects. While these designs, developments and job simulations are desirable and necessary, it is important to understand the limitations of the available field mixing equipment and the ability of that equipment to deliver a cement slurry at the specified density and rates required by these designs. This study investigates the ability of existing mixing equipment to deliver a cement slurry at a specified density and rate.This paper takes data recorded on location and graphically presents it in a three dimension graph of rate, density and volume percentage. This differs from the data presentations available from the service companies. The graphs offered by the cement companies typically plot density, rate and pressure vs. job time. This is useful for determining the events during the job, but does not allow for analysis of the mixing characteristics of the cement unit.This paper presents three dimension histograms from several cement jobs, attempts to evaluate the mixing errors on those jobs, and outlines the efforts taken to correct the problems. A comparison is made to two dimensional histograms evaluating only the density variations. Also presented are data on some jobs where the main objective appears to be the control of the mixing rate, rather than density control. The majority of the data evaluated in this study is from offshore installations. This allows for in-depth evaluation of both the cement unit and the cement delivery system. For consecutive jobs, the same piece of equipment is used, thus eliminating some additional variables in the evaluation.The data reveals several trends in cement mixing. The types of mixing noted in this project are: (1) Mixing where the control of density and rate is very poor, (2) Rate controlled mixing where the mixing rate was the controlling factor, (3) Density driven mixing where concern over the slurry density took precedence over rate and (4) Density and rate control appear to be in concert.From the data evaluated, this analysis method allows for better evaluation of cement mixing, and the quantification of mixing characteristics of various pieces of cement equipment. It will allow for a direct evaluation of the value of adding specific pieces of mixing equipment such as averaging tanks, batch tanks, recirculating mixers, etc. Properly used, the presented evaluation technique should allow the operator to optimize the total cement mixing system through the selection of the most consistent mixing unit.
Interactive Visual Identification of a Reservoir Boundary Integrating Seismic and Well-Test Data
Authors: Swaby P. A. , Beydoun W. B. , Guérillot D. R. 
Published: December 2007

Summary
We describe an interactive system designed to allow users to identify a range of possible reservoir boundaries given a seismic subsurface image and well-test information. Traditionally, data from these two sources are considered separately. This system was developed to interpret both forms of information simultaneously. This is achieved by displaying the seismic image, allowing the user to characterize the seismic uncertainty resulting from the reservoir delineation (i.e., by selecting inner and outer reservoir boundary limits), choosing an intermediate reservoir boundary, running a fluid-flow simulation, and comparing the results with the well-test data. In addition, the system incorporates a multiwindowing interface and has been developed for use by noncomputer specialists.
An Object-Oriented Solution to an Interdisciplinary 3D Visualization Tool
Authors: Sinclair Craig , Little Todd , Rahi M. Ahsan 
Published: December 2007

Summary
This paper describes the design and implementation of an interdisciplinary 3D visualization tool. An object-oriented approach was used to overcome deficiencies within third-party graphical tool kits and incompatible data formats. It also facilitated multidisciplinary visualization by providing a coherent framework for combining drawing technologies from the different disciplines. The tool kit was designed to be extensible and supportable because it was expected to continually evolve to meet new market requirements.
STORM: Integrated 3D Stochastic Reservoir Modeling Tool for Geologists and Reservoir Engineers
Authors: Bratvold R. B. , Holden Lars , Svanes Tarald , Tyler Kelly 
Published: December 2007

Summary
The petroleum industry is focusing on improved reservoir characterization. Decisions concerning development and depletion of hydrocarbon reservoirs must be made while giving consideration to the uncertainties of the formation involved. This requires combining geological and engineering data to develop a detailed reservoir model.
Geostatistics and stochastic modeling techniques have emerged as promising approaches for integrating all relevant information and describing heterogeneous reservoirs. By use of stochastic techniques to generate a range of equiprobable reservoir descriptions, the uncertainty in the important reservoir parameters can be quantified. This quantification, together with the enhanced understanding of the reservoir characteristics given by stochastic reservoir modeling and visualization, provides an essential basis for making informed field-development decisions. This paper presents an integrated approach for stochastic reservoir evaluation. The presented approach has been implemented in the software system STORM.
Pore-Compressibility Study of Arabian Carbonate Reservoir Rocks
Authors: Harari Zaki , Wang Shu-Teh , Saner Salih 
Published: December 2007

Summary
In the laboratory, we determined the pore-compressibility characteristics of some limestone samples obtained from a Saudi Arabian petroleum reservoir. The samples were saturated with water and subjected to confining pressure, pc, and pore pressure, pp, in a core holder, and the resulting reduction in PV was measured. We used differential pressure, pc–pp, ranging from 0 to 4,500 psi. Differential pressure was increased incrementally by reducing the internal (pore) pressure while maintaining a constant hydrostatic confining pressure on the rock samples.
We present the experimental data here in the form of relative porosity and hydrostatic pore-compressibility values as functions of differential pressure. We analyzed the test results after grouping the rock samples on the basis of their lithological description. Four groups of limestone samples consisting of grainstones, packstones, wackestones, and mudstones were studied. Also, Berea sandstone was tested for comparison with limestone. The results show linear negative correlations on a log-log scale between pore compressibility and differential pressure for all the tested samples. Consequently, we computed the pore compressibility vs. differential-pressure power-fit parameters (referred to here as parameters Ac and Bc). We found that parameters Ac and Bc are correlated with initial porosity for the tested samples and inter-related within the same lithologic group. Mathematical expressions for predicting pore compressibility and porosity as functions of differential pressure are given for the tested samples.
Rangely Weber Sand Unit CO2 Project Update
Authors: Masoner L. O. , Wackowski R. K. 
Published: December 2007

Summary
The Rangely Weber Sand Unit miscible CO2 project was initiated in Oct. 1986 and results to date have been encouraging. The development plan of the project has evolved to meet challenges that have developed since startup. Operational changes have also been implemented to improve the economic performance of the unit.
Core Acquisition and Analysis for Optimization of the Prudhoe Bay Miscible-Gas Project
Authors: McGuire P. L. , Spence A. P. , Stalkup F. I. , Cooley M. W. 
Published: December 2007

Summary
Core data from a sidetrack well 250 ft from an old injection well showed intervals of excellent miscible-gas sweep, with miscible-flood residual oil saturations (ROS's), Sorm, of ≈ 5% PV. Less-well-swept intervals had intermediate Sorm values. Numerous intervals had not been contacted by miscible injectant (MI). Chromatographic analyses of the Dean-Stark core extracts quantified miscible-gas alteration of the oil and was especially valuable in the interpretation of intermediate oil saturations. Compositional reservoir simulations showed that high-permeability thief zones and a number of thin shales controlled sweep efficiency near the cored well.
A Novel Recovery Mechanism for Polymer Flooding In Gravity-Dominated Viscous-Oil Reservoirs
Authors: Goodyear S. G. , Mead B. J. , Woods C. L. 
Published: December 2007

SummaryDevelopment of North Sea viscous-oil fields represents a new challenge to the industry. A number of these reservoirs comprise relatively clean homogeneous sands with high horizontal and vertical permeabilities. The oil viscosities are in the range of 5 to 200 cp and oil columns are typically &lt; 200 ft thick and often partially underlain by water. Waterflooding is dominated by gravity in the interwell region, with water slumping to the bottom of the reservoir and coning up to producers. Development depends on the use of horizontal wells to reduce the coning.The viscous oil and poor vertical sweep make these reservoirs possible targets for IOR with polymers. This study shows that polymer incremental recoveries can be high, well within the range of potential economic viability. The incremental recovery mechanism is not the usual improved Buckley-Leverett sweep efficiency resulting from correction of an adverse displacement ratio. A novel recovery mechanism is identified in which the polymer increases the ratio of viscous to gravity forces, reducing the water slumping. This leads to improved vertical sweep, recovering oil from regions of high oil saturation at the top of the reservoir. We simulated polymer flooding including temperature effects. Comparison of waterflood simulations including temperature effects with conventional isothermal simulations shows that, counter to normal expectations, isothermal simulations can underpredict recovery by &gt; 10%.
CO2-Foam Field Test at the East Vacuum Grayburg/San Andres Unit
Authors: Martin F. D. , Stevens J. E. , Harpole K. J. 
Published: December 2007

SummaryThis paper summarizes the response from foam injection in a pilot test conducted at the East Vacuum Grayburg/San Andres Unit (EVGSAU), including results of the reservoir characterization effort and an extensive monitoring program. The paper specifically presents (1) the positive injection-well response (documented with injectivity data and profile logs), (2) the positive production-well response, and (3) the economics of the foam test.
Screening of Oils for In-Situ Combustion at Reservoir Conditions by Accelerating-Rate Calorimetry
Authors: Yannimaras D. V. , Tiffin D. L. 
Published: December 2007

Summary
This paper introduces a new method to screen crude oils for applicability of the air-injection/in-situ combustion process. Testing is performed at reservoir conditions, up to 41.4 MPa, with a specially modified accelerating-rate calorimeter (ARC™). ARC results are shown for four medium- and high-gravity oils, combustion-tube data is presented, and air-injection field data are discussed and compared. We interpret that the continuity of the ARC trace ties in kinetics, combustion-tube, and field air-injection results. Thus, a method is available to delimit the envelope of applicability of air-injection/in-situ combustion to those oil reservoirs where the probability of technical and economic success is greatest.