bluuebunny/crossref_metadata_2025_split huggingface dataset:
Innovative Development Strategy for a Complex Structural-Stratigraphic Trap: A Field Case
Authors: Chen Hsiu-Kou , Thera Jack , Cleveland M. N. , Horner S. G. 
Published: December 2007

Abstract
This paper describes how engineering data and the latest drilling technology are used to develop a complex structural-stratigraphic trap in the Sultanate of Oman. Extended production test and pressure data were used to estimate the oil-in-place and to define the field geometry. This field has a very thin (less than 45 ft) reservoir section located just below a shale cap rock. Development wells are drilled with an inclined pilot hole to determine the reservoir depth, thickness and quality. A short radius horizontal well is then drilled to maximize oil production rate when sufficient pay zone is encountered.
Mechanistic Simulation of Foam Processes in Porous Media
Authors: Rossen W. R. , Zeilinger S. C. , Shi Jianxin , Lim M. T. 
Published: December 2007

ABSTRACT
Foam mechanisms are many and complex, but in some cases the mechanisms that dominate foam properties can be represented in simple models. For instance, fractional-flow methods can reproduce the predictions of much-more-complex foam simulators while highlighting the mechanisms controlling behavior. Fractional-flow methods indicate that the effectiveness of foam processes that alternate injection of liquid and gas ("SAG" processes) depends on foam strength at extremely high foam quality, conditions difficult to control in the laboratory. Ironically, surfactant formulations made with lower surfactant concentration, that form weaker foams in steady-state flow, can foam stronger, longer-lived foams in dynamic SAG processes than foams made with higher surfactant concentration, because water drains more slowly from the "weaker" foams in the SAG process.
A numerical simulator that incorporates the relation between capillary pressure and foam stability extends simplified foam modeling to cases where fractional-flow methods do not apply. Applications of this simulator to one-dimensional (ID) foam displacements match predictions of analytical models based on laboratory data. Applications to 2D flow show that the ability of foam to correct gravity override is controlled both by the dimensions of the reservoir and the allowable rise in injection-well pressure. In flow through layers in capillary contact, the interplay between capillary cross-flow and foam collapse depends on both the dimensions of the layers and the relative magnitudes of the capillary and viscous pressure differences.
Study of Removing Formation Damage by Solidified Polymer in Extremely Hot Wells
Authors: Krilov Z. , Tomic M. , Loncaric B. , Cikes M. 
Published: December 2007

Z. Krilov,* M. Tomic, B. Loncaric* and M. Cikes*

Abstract
The paper is describing the problem of identification of an inconvenient type of formation damage due to polymer solidification downhole. Laboratory tests showed the presence of this problem if particular temperature has been exceeded. Based on lab test results the method of chemical treatment was developed in order to remove this kind of damage. The comparison of laboratory investigation data and field application of method is expressed.
The severe damage of production zones were occurred after using a gelled brine system for temporary viscous plugs set in some deep hot gas condensate wells in Southern Pannonian basin (BHT&gt;195 C, TWD &gt;4000m). Laboratory tests showed solidification of the same calcium bromide-calcium carbonate high activity synthetic polymer (polyacrilate) Water base system at temperature above 180 C. So formed viscoelastic material (solidified polymer) has plugged perforation tunnels and near wellbore porous medium, causing drastic reduction in well productivity.
The laboratory tests and attempted well stimulation jobs showed that this type of residuum is practically undissolved in any well known solvent or acid. Due to further lab investigations the way of chemical treatment, using sequential injection of base (KOH) or oxidant (NaOCl + NaOH), following by inhibited organic acid (CH3COOH) was developed and successfully used in field practice to remove formation damage downhole.
The described method of treatment, accompained with laboratory analytical procedure for damage identification, can be applied in designing the well stimulation jobs.
P. 743
A New Concept in Scale Inhibitor Formation Squeeze Treatments
Authors: Miles Leon 
Published: December 2007

Abstract
Scale control in producing wells has been a particularly thorny problem because scale often begins in the formation before the scaleforming fluids reach the wellbore. Continuous treatment down the casing annulus protects down-hole equipment but does not attack the scale at its starting point. Squeeze treatments with liquids and fracture packs with solid scale inhibitors have not been entirely successful because of short treatment life.
A squeeze treatment utilizing a liquid which forms a slowly soluble inhibitor in situ has been developed and field tested with excellent results. Field histories over a period of 30 months are now available. The period of 30 months are now available. The field histories support the laboratory data upon which the treatment was based.
Introduction
Scale may be defined as a mineral deposit formed on surfaces in contact with water. The most common scales associated with oilfield brines are calcium sulfate, barium sulfate and calcium carbonate. Other insoluble salts are also found, but usually in small quantities along with these three. Corrosion products such as iron oxide and iron sulfide may also be considered as scale.
Many industries face scale problems, but those handling brine from deeply buried formations are plagued with a unique combination which makes scale control very difficult. We usually handle very large volumes of poor quality water under severe temperature and pressure conditions. Our main problem is the pressure conditions. Our main problem is the remote and nearly inaccessible location for treatment where the trouble really begins. A thorough understanding of scale formation is required before successful treatment can be assured.
Causes of Scale Deposition
Three major causes of scale deposition have been identified.
A Mixture of Two Incompatible Waters
One mixture possibility is foreign water entry into the producing zone from casing leaks or poor cement jobs. Obviously, this problem should be solved by more direct methods than chemical treatment. Another possibility not so easily overcome may occur at producing wells when injection water breaks through. Bernard has shown that no reaction occurs within the formation pore space when water incompatible with formation water is injected. He reasoned that discrete pore channels were filled with injection water displacing formation water. No opportunity for mixing presents itself until both formation water and injection water, flowing in separate pore channels, make contact at the producing wellbore face. At some point in time, a ratio of the two would then result in precipitation and scale. precipitation and scale.
Simulation of Crawford Gas Storage Field
Authors: Nacul E. C. , Gilmore R. , Theodos A. 
Published: December 2007

ABSTRACT
The Crawford Field is a very large gas storage field located in Hocking and Fairfield Counties, Ohio. The Crawford field lies along the distal edge of the clastic wedge that forms the Silurian aged Clinton delta complex. The Clinton sands in the field consist of multi-stacked, coalescing, lenticular sandstones and siltstones deposited as distributary channel sands, interbedded with marine shales and floodplain muds. The Clinton sequence strikes N 17° E with a dip to the southeast of about 62 ft/mi.
The main purpose of the study was to create a strategic plan for developing the Crawford gas field for storage operations in the most efficient and cost effective manner. In the study we have verified the number of wells required in the Crawford Gas Storage Field to inject and withdraw the monthly schedule assigned by Columbia Gas Transmission Corporation, determined the best well priority for the field, and defined the amount of gas migration northward into an undrilled future development area of the field.
In order to accomplish this study, the reservoir area of approximately 40,000 by 70,000 feet was gridded in a 45 by 75 single layer model with uniform cells of aspect ratio of 1.062. A history match of 3 cycles (1989 to 1993) was performed with a very good agreement between the simulation and field results. With the reservoir description adjusted from the history match a 3 cycle forecast (1993 to 1996) was performed. This forecast allowed Columbia Gas Transmission Corporation to analyze the Crawford Gas Storage Field capability for the next three years.
Evaluating the Optimal Norwood Deepening Method in the Antrim Shale
Authors: Frantz J. H. , Tatum C. L. , Bezilla Michael , Kalnbach B. W. , Wilkinson J. G. 
Published: December 2007

ABSTRACT
The purpose of this paper is to present the results of a Gas Research Institute (GRI) evaluation to determine the optimal deepening and completion technique for the Norwood Antrim Shale unit in older Antrim wells in the Michigan Basin, including the potential range of Norwood production responses. There are approximately 500 older Antrim wells not drilled through the Norwood, that could be deepened below their current Lachine unit completion. GRI performed this work because operators are uncertain of the best deepening/completion procedure, the potential productivity of the Norwood, and the appropriate well spacing for the Norwood completions. In this paper, we show the results of actual field case histories and simulated performance projections to determine the optimal Norwood deepening method and well spacing.
Production Study Evaluates Completion and Stimulation Program
Authors: Zamora Frank , McDaniel B. W. , Hyde Paul 
Published: December 2007

Abstract
Completion techniques and associated stimulation treatments used for wells in the Devonian Shale of the Appalachian Basin have been evaluated in a 2-year study of production logs and production history. The study was a joint effort of a gas production company and a well service company. Results of the study have revealed that well economics can be significantly improved if completion zones are better chosen and the appropriate associated fracture stimulation treatment is used. This paper presents study methods, findings, conclusions, and recommendations on completion plans and stimulation designs for future wells in this field and similar Devonian Shale wells.
The Use of Well Log Data for Estimating Permeability in a Heterogeneous Reservoir
Authors: Molnar D. L. , Aminian Khashayar , Ameri Samuel 
Published: December 2007

ABSTRACT
The determination of the permeability distribution in a heterogeneous reservoir is the key for performance predictions. The permeability is usually evaluated from cores and/or pressure transient well tests. The determination of the permeability distribution in a heterogeneous reservoir is a complex problem because core samples and well test data are only available from very limited number of wells. At the same time, geophysical logs are available from the majority of, if not all, the wells in a reservoir. Therefore, the evaluation of permeability from well log data represents a significant technical as well as economic advantage. The evaluation of permeability in heterogeneous formations from well log data however represents a difficult problem. Generally, a simple correlation between permeability and porosity cannot be developed in heterogeneous formations. The goal of this study has been to investigate the feasibility of estimating the permeability of a heterogeneous formation utilizing geophysical well logs as well as geological interpretations.
Granny Creek Field in West Virginia has been selected for detailed evaluation in this paper. This field has produced oil from the Big Injun Formation since early the 1900's. Water flooding operations were initiated in the 1970's and currently are in progress. Well log data from a substantial number of wells, as well as core samples and/or core analysis results from a limited number of wells, were available and were collected. The core samples and the various well logs were analyzed to determine permeability and porosity. However, a reliable porosity-permeability correlation could not be developed even when the formation was subdivided into several zones based on the various geological interpretations.
A methodology was developed in this study by integrating actual well log responses (Gamma Ray, Deep Induction, and Bulk Density) and geological interpretations to subdivide the formation into several zones which led to development of a reliable correlation between bulk density and permeability. The field-wide applicability of the correlation was verified through comparison against measured permeability values, The results presented in this paper could serve as a guideline for correlating permeability with well log data in heterogeneous formations.
A New Technique for Analysis of Wellbore Pressure From Multi-Layered Reservoirs With Unequal Initial Pressures To Determine Individual Layer Properties
Authors: Aly Ahmed , Chen H. Y. , Lee W. J. 
Published: December 2007

Abstract
In this paper, we present a new method for analyzing a multi-layered, commingled reservoir with unequal initial layer pressures. The main objective is to provide techniques and methodology to determine the individual layer permeabilities, porosities and skin factors from the pre-production well test data. The layer information obtained early in the life of the reservoir is very important for planing production schedule and economic decisions concerning the future of the wells. This pre-production well test is carried early in the life of the reservoir, during the period after perforation but before any surface production and is caused by crossflow in the wellbore only.
The results of this study provide a useful foundation for the design of a new pre-production well test procedure that ensures that the individual layer properties are measured adequately and early in the life of th6 reservoir when they are most needed.
The pre-production well test requires no production on surface. Thus, the environmental impact caused by flaring oil or gas during a conventional well test is alleviated.
Fontenelle Field Hydraulic Fracturing Stimulation of the Frontier Formation: Case History
Authors: Martinez A. D. , Ruffin B. D. 
Published: December 2007

ABSTRACT
This paper is a case history of the Frontier Formation hydraulic fracture stimulations applied since 1984 in the Fontenelle Field located in Sweetwater County, Wyoming. The hydraulic fracture treatments have undergone several design changes that have led to a 25% increase in production and a 66% decrease in completion costs.
Design changes that have been incorporated to reduce costs include reduction in pad volumes, use of sand versus intermediate strength proppant, reduced pump rates, and the use of water based gels instead of CO2 foams. Improved production is attributed to improved fracture geometry resulting from 3-D fracture model analysis.
Rose Run Stimulation: A Case History of Problem Identification, Research, Planning, Implementation, and Evaluation
Authors: Cramer J. W. , Thomas J. B. 
Published: December 2007

ABSTRACT
The Rose Run Sandstone consists of individual quartz and feldspar grains cemented by dolomite, clay minerals, and overgrowths of quartz and feldspars. Historically, the Rose Run has been stimulated with hydrochloric(HCl) acid with appropriate additives to remove the dolomitic cement matrix to improve permeability. Post stimulation results vary widely.
The production from some wells suffered from steep declines. When shut-in, most wells exhibited good pressure recovery. Reservoir analysis calculated skin factors as high as +10 indicating formation damage.
An in-depth study of wells in Randolph Township of Portage County, Ohio (Fig. 1) was initiated to try to identify the mechanisms that effect well productivity. Drill cutting samples, well logs, rotary sidewall cores, petrologic data, core analysis, and SEM photos were analyzed. The primary goal of this study was to determine possible improvements to current stimulation treatments. An additional benefit of this study was to evaluate the viability of remedial acid treatments in removing damage from producing wells.
Drill cutting samples, mud logs, natural production shows, and well logs are used on site to determine if the well would be completed.
Rotary sidewall cores were obtained from several wells for in-depth analysis. Routine laboratory core analysis measured permeability, porosity, and core fluid saturations. Thin sections were prepared and SEM photos were taken for petrographic analysis. Rotary sidewall cores from one well were analyzed and deemed representative of the Rose Run Sandstone. Rotary sidewall cores were tested to determine initial permeability to Rose Run formation brine and regained permeability to various acid solutions. The results of all analyses were considered in revising initial well stimulations as well as designing remedial acid treatments to address the problems that have been identified.
Production rates, decline curves, and pressure build-up data of conventionally treated wells were compared to wells treated with a new acid solution to determine if any positive benefits could be realized. The evaluation of remedial acid treatments using the new acid solution was based on the treatments ability to reduce the rate of production decline.
Techniques for Determining Subsurface Stress Direction and Assessing Hydraulic Fracture Azimuth
Authors: Hill R. E. , Peterson R. E. , Warpinski N. R. , Lorenz J. C. , Teufel L. W. , Aslakson J. K. 
Published: December 2007

ABSTRACT
This reference paper reviews and describes 15 techniques for determining hydraulic fracture azimuth. The techniques described are categorized into core-based, borehole-based, near-wellbore, and regional geologic indicators that can be used to predict or measure hydraulic fracture azimuth. The core based methods include: 1) circumferential velocity anisotropy, 2) anelastic strain recovery, 3) differential strain curve analysis, 4) axial point load tests, 5) petrographic examination of microcracks, 6) overcoring of archived core, 7) drilling-induced fractures in core, and 8) direct observation of over-cored open-hole stress test fractures. The borehole based techniques include: 9) borehole breakouts, 10) borehole deformation, 11) borehole imaging of drilling-induced fractures, and 12) directional gamma ray logging. The near-wellbore techniques provided data on the orientation of the fracture induced during an actual fracture treatment and include: 13) microseismic logging and 14) earth tilt surveys. Finally there are the geologic indicators (Method 15) including earthquake focal mechanisms, fault slip data, surface mapping of neotectonic joints, and volcanic vent alignment. These regional data have been compiled for the World Stress Mapping Project and many maps are available that can be used as a first approximation of stress direction.
Experience has shown that the more techniques that can be used in a single well or field, the more reliable the result. The concept or theoretical basis for each technique as well as the benefits and limitations of the techniques are described.
Drilling Fluids Waste Minimization and Stabilization Using Polymer Technology
Authors: Thompson L. F. 
Published: December 2007

ABSTRACT
The purpose of this paper is to address environmental issues associated with generated waste through drilling. Polymers have been proven to be extremely effective in the waste reduction in drilling closed system without the use of solids control equipment with shale shakers optional and the stabilization of drilling discharges using additional polymer technology. The objective is to demonstrate that with the proper use of polymers, waste can be reduced and stabilized without an increase in volume and with a very cost effective method. The result is that the environment will be enhanced while reducing risks and costs.
The Development and Field Application of a 3D Computer Graphics System for Displaying Wellbore Trajectories
Authors: Santos O. L. A. , Azar J. J. 
Published: December 2007

ABSTRACT
This paper presents the development of a 3-D computer graphics software for displaying wellbore trajectories. The software is designed for use with PC microcomputer operating under MICROSOFT WINDOWS™ environment. Examples of the software application are given in two important areas of directional drilling: 1) avoidance of wellbore collisions and 2) planning and drilling monitoring of relief wells.
First, the paper presents the basic theory behind the computer graphics techniques used for developing the computer software. Second, it presents the display modes and important features provided by the system that includes 2-D and 3-D views of wellbore trajectories with ability of rotation, zoom-in and zoom-out, and display of uncertainty ellipses. These features are very helpful in planning and monitoring wellbore trajectories. Also, these capabilities allow the software to be used as a powerful training tool.
The last part of the paper illustrates the application of this graphic system in planning and monitoring: 1) directional drilling in high density well areas such as offshore platforms in order to avoid wellbore collision; and 2) the relief well drilling to assist in the approaching procedure between relief and blowing wells and the use of ranging tools.
Characterization of Devonian Shale Gas Reservoirs Using Coordinated Single Well Analytical Models
Authors: Carlson E. S. 
Published: December 2007

SUMMARY
We present here a simple, fast methodology which can be used to provide information about the two least-measurable parameters of Devonian Shales, fracture spacing and fracture continuity. The results of these calculations can assist in establishment of field development programs. Although this technique may provide for the most detailed characterization possible for the shales, we show the clear need for further research into geophysical and other geological methods for detection of fracture densities.
Predicting Compaction and Subsidence for an Immature Gasbearing Carbonate Field
Authors: Prins M. , Smits R. M. M. , Schutjens P. M. T. M. 
Published: December 2007

ABSTRACT
Reservoir compaction and associated surface subsidence levels can be significant when high porosity carbonate gas reservoirs are depleted. A well known example is the Ekofisk field in the North Sea Therefore these phenomena are incorporated when designing offshore platform constructions. Because the design and the construction part of development take place well before the field production starts (i.e. when only little is known about the field), uncertainties exist in the parameters that are required for the prediction of surface subsidence.
This paper describes the prediction of subsidence for the M1 field, offshore Sarawak, East Malaysia and shows that although many uncertainties may exist in the parameters required for the predictions, investigation into the effects of these uncertainties provides useful insight in the possible range of subsidence levels. The predicted range of subsidence levels can subsequently be used as input for the platform design.