bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Study of Particulates Migration in Gravel Pack
Authors: Bouhroum Ahsene , Civan Faruk 
Published: December 2007

ABSTRACT
Existing geometrical gravel-pack design criteria do not consider the effect of sand migration through and clogging of the gravel-pack matrix. Therefore, a visual and qualitative laboratory investigation of moving particulates through gravel-pack confined within a parallel configuration (linear) and a convergent configuration (radial) visual cells, has been carried out. Castings of the clogged gravel-pack have been studied to obtain information about the geometrical alteration and deposition morphology. The structural changes due to the clogging process have been characterized by injecting a NaCl-tracer and by analyzing the breakthrough curves (BTCs) before and after clogging.
Results indicate that the migration of particulates into the gravel-pack is a time dependent process which is completed when a self-filtration zone of intruded fine particulates is formed next to the interface of the gravel-pack-particulates at a given flow rate. The particulates migration process is characterized by a discontinuity of particulates concentration. The concentration of particulates is high up to a well-defined line located at the interface. Ahead of the front, there is very little or no particulates at all. It is further observed that an empty pore just ahead of the moving front of particulates remained almost entirely empty until the concentration of moving particulates within the pore immediately behind it is sufficiently high. In this way, the well-defined front of particulates moves through the gravel-pack, conquering pore after pore. It is shown that dispersion measurement characterizes the changes in the structure and therefore in the flow pattern accurately. Tracer analysis indicated that the clogging process created multiple flow paths manifested in highly tailed breakthrough curves.
Besides providing the parameter values for models, these observations indicate that it is necessary to consider a collective motion of particulates instead of the classical particle-by-particle approach used in phenomenological models.
Formation Damage Studies on Reservoir Rocks Using Water-Base and Oil-Base Muds
Authors: Tovar Jose , Azar J. J. , Lummus J. L. , Sarma D. S. , Pilehvari Ali 
Published: December 2007

ABSTRACT
An experimental study was undertaken to investigate the mud solids and filtrate invasion in reservoir rocks while using drilling muds. The objective of these experiments is two fold: one is to evaluate the performance of various reservoir rocks and select the most compatible drilling fluid, and second is to delineate the pore blocking mechanism that causes formation damage. Core plugs of Berea sandstone, dolomite and limestone were examined by petrographic methods and tested for permeability reduction during mud circulation. Both of water-base and oil-base muds that are typically used in field studies were obtained and tested for their performance evaluation.
Data from these tests shows that particles from these drilling muds penetrated well into the interstices of the formation, causing a significant reduction in absolute permeability of the rocks. Higher the initial rock permeabilities of the rocks, higher and much deeper were the impairments. An average reductions of 50 to 80% of oil mobilities were found in case of Berea sandstones when exposed to various muds. In cases of light formations, like limestones tested here, reduction in oil mobilities were found to be 30 to 40%. The location and extent of damage, also varies with other parameters such as mud annular velocity, differential pressure, characteristics of the rock as well as the characteristics and composition of the mud filtrate and solids that flow with it under dynamic conditions. A mechanism of permeability reductions in reservoir rocks is proposed based on the filter cake properties and the test data. Effective guidelines for selecting a proper drilling mud can be obtained as an outcome of this work.
Underbalanced Drilling: Formation Damage Control During High-Angle or Horizontal Drilling
Authors: Shale L. T. 
Published: December 2007

ABSTRACT
Because underbalanced drilling creates a natural tendency for fluid to flow from the formation into the borehole, successful underbalanced drilling depends on appropriate selection of circulating fluid. Under these conditions, use of conventional mud systems often results in lost circulation, formation damage, high mud costs and a need for expensive completions. Use of compressible fluids, on the other hand, can inhibit or eliminate many of the problems associated with drilling in environments in which formation damage is likely.
Use of a compressible fluid in the circulating system, referred to as air drilling, lowers the downhole fluid pressure, allowing drilling into formations where loss of circulation and damage to productive formations are problems of major concern.
Other advantages to air drilling include increased penetration rates, improved drill bit performance, and contamination-free drill solids for ready detection of hydrocarbons.
Reduced pressure air drilling techniques include not only gas continuous phase methods and use of dry gas and gas mist, but also gas internal systems with stable foams and aerated fluids.
This discussion of problems related to underbalanced drilling addresses types of drilling equipment used, and provides an overview of experience gained from both successful and unsuccessful wells.
Control of Fines Migration: A Key Problem in Petroleum Production Industry
Authors: Rahman M. S. , Rahman S. S. , Arshad Aziz 
Published: December 2007

ABSTRACT
Prevention of formation damage due to release and deposition of fines in reservoirs is important to enhance oil production. It is, therefore, essential to know the critical conditions at which particles release and plug the pore channels. This paper presents a physical model of the process of particle deposition in porous network based on a novel experiment in which suspensions of particles were passed through micro capillaries of different diameters [60 and 100 μm] at different velocities and the rate of particle deposition and consequent pressure build up were monitored. An improved 3D trajectory analysis was developed and it was validated by observing the rate of particle deposition in a micro capillary while injecting bentonite suspensions at different velocities and particle concentrations. A criteria is proposed to predict the critical conditions for particle deposition in a micro capillary.
Control of Formation Damage by Modeling Water/Rock Interaction
Authors: Bazin Brigitte , Souto Esperanza , Thiez Piérre Le 
Published: December 2007

ABSTRACT
Modifications of flow properties may be observed when injected brine replaces formation water, especially when the salinity of the injected brine is lower than the resident one. This is generally attributed to detrimental physico-chemical rock/fluid interactions such as ion exchanges. This paper concerns ion exchange mechanisms related to permeability damage.
A laboratory study conducted in batch and flow conditions relates the permeability reduction to the physico-chemical rock interaction. Batch experiments aim to determine the Critical Salt Concentration (CSC) for clay deflocculation. Flow experiments show the effect of pH and water composition on the permeability reduction in a transient region resulting from ion exchanges. These experiments are represented by a flow model involving ion exchange, CSC and permeability reduction. The modeling of the physico-chemical interaction in flow conditions compares very well with experimental results in a wide range of situations.
A 3D chemical model including two phase flow and physico-chemical equilibria is presented for extrapolating laboratory data to reservoir scale. The numerical study evaluates the effect of the composition of both the resident brine and the injected solution on the resulting properties of the reservoir.
The conclusions obtained from the simulations enabled us to deduce different strategies for optimizing well treatment or water injection. It is shown that detrimental permeability effects can be avoided by adjusting the water compositions.
Phosphonate Scale Inhibitor Adsorption/Desorption and the Potential for Formation Damage in Reconditioned Field Core
Authors: Jordan M. M. , Sorbie K. S. , Jiang Ping , Yuan Ming Dong , Todd A. C. , Hourston K. E. 
Published: December 2007

Abstract
Scale inhibitor "squeeze" treatments are used extensively to control problems with downhole carbonate and sulphate scale formation. The return curve from an adsorption/desorption squeeze is governed by the inhibitor/rock interaction which, in turn, is described by the adsorption isotherm. Several factors, such as pH, [Ca2+], temperature, rock mineralogy etc, affect the adsorption level and the shape of the adsorption isotherm. However, these same factors may also lead to deleterious effects in terms of both formation damage and inhibitor solution effectiveness; the latter effect is referred to in this work as "fluid damage".
In this paper, results and discussion are presented on the potential for formation damage and inhibitor fluid damage when acid phosphonates are applied in clastic reservoir formations. Results are presented from an extensive series of phosphonate (DETPMP) scale inhibitor core flooding experiments using Brent Group (North Sea) sandstone cores as the adsorbing substrate. Careful effluent analysis along with detailed petrography and permeability measurement before and after core flooding are shown to be invaluable in assessing the degree of formation damage (and "fluid damage") arising due to several factors. Most of the points raised here are quite general and they are illustrated by the specific field results. This work therefore contributes to the development of safer field applications of scale inhibitor squeeze treatments in the light of individual reservoir petrography.
Produced Water Re-Injection; How Clean is Clean?
Authors: Coleman J. R. , McLelland W. G. 
Published: December 2007

Abstract
A frequently asked question concerning the re-injection of produced water is: ‘How clean must the water be to avoid injection well plugging problems?’ Over the years, industry has developed several techniques to establish cleanliness specifications.1-5 These techniques include both on-site coreflood studies as well as laboratory investigations. The specifications derived from these tests often include maximum allowable values for the content of solids and residual or emulsified oil in the water. Recent field and laboratory studies indicate that two of the most widely used specifications, oil-in-water and total suspended solids, may not provide the best indication of whether a produced water will or will not plug a target formation.
Field data suggest that the plugging characteristics of a produced water may better be defined by the term Total Filterable Solids. This term treats suspended oil as a solid rather than a liquid. The field data also shows that there was no increase in plugging frequency even after an unexpected and significant increase in the oil content of a produced water system at Prudhoe Bay, Alaska.
Laboratory studies, which correlate with field experience, are also presented. The laboratory studies show that produced waters containing relatively high concentrations of oil-in-water can be re-injected as long as the oil droplet size is less than or equal to the average pore throat diameter of the reservoir. Furthermore, these lab studies show that it is important, when developing new produced water specifications, that core flood experiments be conducted on cores at residual oil saturation rather than brine or water saturated cores.
Formation Injectivity Damage Due to Produced Water Reinjection
Authors: Hsi C. D. , Dudzik D. S. , Lane R. H. , Buettner J. W. , Neira R. D. 
Published: December 2007

Abstract
On-site coreflood experiments were conducted at Prudhoe Bay field, Alaska using side streams of produced water taken directly from produced water injection (PWI) lines. The objectives were to determine how rapidly the formation injection face is plugged by produced water re-injection, the location and mechanism of damage, and the impacts of bacterial growth on the extent and rate of damage.
In core tests where produced water was not filtered prior to injection, 90% permeability damage occurred within 24 hours of injection startup. This is inconsistent with field observations where injection well decline is observed to occur over weeks or months, when seen at all. Field observations are consistent with previously-described (growing) thermal fractures that dominate injection performance, thereby minimizing deleterious effects of sand face plugging.
In core tests where produced water was filtered, little damage was observed; this demonstrates that removable components in produced water are responsible for face damage. However, when cores were first inoculated with bacteria-laden water and then flooded for several days with filtered produced water, deep damage (inches) was seen. This suggests PWI wells can suffer injectivity damage over time due to bacterial growth.
Once damage had occurred, addition of biocide did not restore permeability.
Development of an Expert System for Water Control Applications
Authors: Wu F. H. , Chiu T. J. , Dalrymple Dwyann , Dahl Jeff , Rahimi A. B. 
Published: December 2007

Abstract
Accurately diagnosing and treating a water control problem can often be costly and difficult. Although numerous water control products and treatments are available, only a small percentage achieve the desired results because the problem was misdiagnosed, the incorrect treatment design was chosen, or operational problems occurred.
A knowledge-based expert system is now available that can help identify possible problems and provide a complete treatment design. Since the knowledge required in this case may involve some uncertainty, a set of numerical probabilities must be used to represent this information. In addition to the rule-based reasoning1 commonly used by many expert systems, this system includes a unique matrix technique that can use available reservoir, production, and injection information to diagnose problems based on probability.
After identifying all potential problems, the system can recommend the most effective treatment for each type of problem, provide an optimum treatment schedule, and introduce the best placement technique based on available data. This type of expertise can be best represented by production rules. The system also features an extensive explanation facility to help the user understand why each recommendation was made.
This PC-based system can operate in a Microsoft® Windows™ environment. Unlike previously designed systems2requiring an AI shell, C language was used to develop this system.
This paper will address the various design considerations involved in developing this knowledge-based system. Specifically, it will discuss the following topics:
the knowledge acquisition process knowledge representation and system implementation, including – problem identification/reasoning (using the matrix technique) – fluid selection/placement techniques (using the rule-based technique) the operation of the user interface
Reservoir Management of the Fullerton Clearfork Unit
Authors: Bane R. K. , Parker R. A. , Storbeck W. G. , Sunde R. L. 
Published: December 2007

ABSTRACT
The Fullerton Clearfork field, Andrews County, Texas, was discovered in 1942 and waterflooding was initiated in 1956. Field development continues through infill drilling, injection conversions, and add-pay workovers. Recent reservoir management efforts in the Fullerton Clearfork Unit have concentrated on improving workover and drill well economics, and optimizing waterflood performance. This paper discusses techniques that have been developed to identify potential thief zones, improve perforation selection in workovers and drill wells, balance waterflood patterns, and optimize location selection for new drill wells. The flood balancing techniques described in this paper have been implemented in a test area and results from this test will be discussed. Results from recent workovers, conversions, and drill well programs will also be discussed.
Analyzing Well Logs from the Montoya Lime Using a New Carbonate Well Log Interpretation Procedure
Authors: Walsh J. W. , Brown S. L. , Asquith G. B. 
Published: December 2007

Abstract
Analyzing well logs from carbonate formations is difficult because of the problem in estimating the cementation exponent (m) and calculating correct porosities in complex lithologies. Generally, determining lithology can be accomplished using multiple porosity crossplots. If the pore type is known or can be determined from well logs, m can be calculated more accurately using variable m models based upon pore type. A series of logging crossplots can be used to determine the appropriate pore type. Whether the zone is wet or productive can be estimated through the use of several hydrocarbon indicating crossplots. This paper outlines the general analysis for carbonates including estimating lithology and pore type, determining hydrocarbon presence, and computing porosity, m, water saturation, and net pay. An example from the Montoya Lime illustrates the procedure.
Oil or Fresh Water? A New Through-Tubing Measurement to Determine Water Saturation
Authors: Streeter R. W. , Hogan G. P. , Olson J. D. 
Published: December 2007

ABSTRACT
This paper presents log examples and describes the use of Cation/Oxygen ratio (CATO), a Carbon/Oxygen type measurement, to discriminate fresh formation water or water of varying salinity from oil. Instead of using the ratio of carbon to oxygen (C/O), CATO is the ratio of all inelastic gamma rays except those from oxygen, to the oxygen inelastic gamma rays. CATO responds to the presence of oil similarly to C/O, but has several advantages:
(1) CATO can be recorded using a combination 1⅝" Pulsed Neutron Decay-Inelastic gamma ray tool that uses Sodium Iodide crystals, (2) Variations in lithology have much less effect on water saturations, (3) Statistical fluctuations are significantly reduced, (4) The sensitivity to oil is an order of magnitude greater, and (5) Logging speeds are increased to 8 to 12 feet per minute.
Log examples are from sandstones and carbonates and include CATO responses in water floods with unknown water salinity and from formations with low salinity connate waters. Production and test results are also presented. Operating limitations of the technique are given.
Depth of Investigation for Hydraulically Fractured Wells: Field Applications
Authors: Lio Yizhu , Lee W. J. 
Published: December 2007

ABSTRACT
This paper presents two examples to illustrate the uses of "depth of investigation" for hydraulically fractured wells in oil and gas reservoirs. Both high and low conductivity fractures are represented. We present calculations of depth of investigation for hydraulically fractured wells. We examine reservoir pressure distributions at different flow times.
Laboratory Flow Tests Used to Determine Reservoir Simulator Foam Parameters for EVGSAU CO2 Foam Pilot
Authors: Chang Shih-Hsien , Grigg R. B. 
Published: December 2007

Abstract
This paper presents the results of laboratory foam tests that will be used to determine foam parameters for use in foam-flood reservoir simulators. Foam tests were performed at average reservoir conditions of 101 °F and 2100 psig with EVGSAU cores. Foam was generated in situ by simultaneous injection of surfactant solution and C02 into a brine-saturated core. In this study, the gas-liquid volumetric injection ratios of 2, 4, and 6 (with foam qualities of 66.7%, 80.0%, and 85.7%, respectively) were examined. The flow rate in terms of total interstitial velocity varied from 0.36 to 34.38 ft/day. The surfactant was tested at concentrations of 1000 and 2500 ppm active.
The resistance factor of each test ranged from 3 to 63, indicating that foam was generated at all the testing conditions. Brine permeability, which changed after each foam test, had a significant effect on the calculation of foam apparent viscosity. Because of varying brine permeability, the resistance factor data is more suitable for simulator input than the apparent viscosity data.
CO2 Huff 'n' Puff Field Case: Five-Year Program Update
Authors: Miller B. J. , Bardon C. P. , Corlay P. 
Published: December 2007

ABSTRACT
CO2 Huff 'N' Puff has been used on a shallow light oil field to add value to existing oil producing wells by increasing the ultimate oil recovery. Testing was initiated in 1985 with a more continuous program starting in 1989.1 The application of CO2 Huff 'N' Puff has increased oil production 180,000 bbls above the primary recovery with the use of 210 MMCF (12,200 tons). The CO2 treatments have been relatively small with 390 treatments performed on 240 wells.
North Dollarhide (Devonian) Unit: Reservoir Characterization and CO2 Feasibility Study
Authors: Kovarik M. J. , Prasad R. K. , Waddell Wade , Watts George 
Published: December 2007

ABSTRACT
In order to implement a CO2 flood in the North Dollarhide (Devonian) Unit (NDU), detailed reservoir characterization and engineering studies were prepared using 3-D seismic, classical geology and reservoir engineering, and a fieldwide reservoir simulation. Routine and special core analyses, PVT analyses, and well tests taken during recent development aided in the reservoir and fluid characterizations. A black oil reservoir model matched available production and pressure history of the reservoir, and forecasted future production under water injection and CO2 injection using mixing rules developed with the aid of a 1/4 5-spot compositional model. History matching presented a special challenge since Devonian and uphole Clearfork production was commingled between late 1970 and 1990, and therefore actual Devonian production and pressures were not implicitly known.
Foamed Cementing Technique for Liners Yields Cost-Effective Results
Authors: Pickett S. L. , Cole S. W. 
Published: December 2007

ABSTRACT
This paper details the application of a constant density foamed cement technique for liners. The liners were approximately 6200' in length. The liner top was at 4400' and extended to TD at 10,600'. Most of the liner cement consisted of a 9.0 lbm/gal foam. The mud column above the liner had a density of 8.7 to 9.1 lbm/gal. It was demonstrated that relatively long columns of foamed cement could be accurately placed and remain stable in a liner cementing situation. The cement jobs took place on 15 wells during 1991 and 1992. An improvement in cement quality and a reduction in costs resulted from using this cementing technique.