bluuebunny/crossref_metadata_2025_split huggingface dataset:
Characterization of a Naturally Fractured Carbonate Reservoir: Lisburne Field, Prudhoe Bay, Alaska
Authors: Belfield W. C. 
Published: December 2007

Abstract
A synthesis of data from cores, production logs, well tests, and well performance is used to provide both a preliminary description and an estimate of parameters necessary for numerical simulation of a naturally fractured, multi-layered carbonate formation under primary depletion.
Core fracture analysis indicates the presence of open fractures immediately beneath an unconformity surface that marks the top of the formation. The interpretation that these fractures provide substantial permeability is confirmed by spinner logs (which indicate large decreases in productivity short distances below the unconformity) and injection surveys (which show large quantities of injected fluid being accepted by the formation just below the unconformity). Rapid pressure response between adjacent wells during an interference test is attributed to this fracture system. The fracture system is believed to be spatially related to the unconformity surface. Other fractures recognized in core are partially open and appear to be discontinuous on a core scale. These fractures are believed to enhance matrix permeability rather than act in the manner of fractures associated with a dual-porosity system.
Production in the reservoir is from both fractures and from vertically extensive.
better quality matrix zones. Partitioning the total permeability-thickness (kh) value between these two modes of productivity is problematical. Matrix kh can be estimated by using log porosity and a core derived porosity/permeability transform. Justification for this approach is found in approximately linear semi-log plots of permeability versus porosity of full-diameter cores measured under overburden stress.
Total kh values (determined from pressure transient tests) are cross-plotted with productivity indices for a series of wells. A straight line fit to the data is considered to be representative of Lisburne well productivity. Use of this plot permits an estimate of total well kh for any well in the field, given a calculated productivity index. Corresponding apportionment of fracture kh and matrix kh can then be made for the well. This approach greatly expands the data base available for inferring effective fracture or fracture kh distributions beyond that determined from limited core and well-test data.
Flow Regimes in Vertical and Inclined Oil/Water Flow in Pipes
Authors: Zavareh F. , Hill A. D. , Podio A. L. 
Published: December 2007

ABSTRACT
Flow regime behavior in upwards oil-water flow has been studied in a large diameter, inclinable, multiphase flow loop. With the pipe vertical, bubble flow occurred for all conditions tested. When the pipe was inclined by 5 or 15° from vertical, a new flow regime, countercurrent bubble flow, was observed over a wide range of flow conditions. Theoretical flow regime maps developed for gas-liquid flow did not properly predict oil-water flow regime behavior.
Intelligent Pigging of the Ekofisk-Emden 36-in. Gas Pipeline
Authors: Nespeca G. A. , Hveding K. B. 
Published: December 2007

ABSTRACT
The Intelligent Pigging of a major gas pipeline requires careful planning and execution to obtain successful results as well as to maintain production and to avoid disruption of gas contract commitments. Although it is costly to implement such inspections, the information obtained can be invaluable to the operation and is a vital part of the maintenance program of a strategic North Sea gas transmission pipeline. This paper describes the preparatory work, actual performance and findings obtained from an inspection using a "state of the art" magnetic flux inspection vehicle.
Reduction of Jet Perforator Penetration in Rock Under Stress
Authors: Halleck P. M. , Saucier R. J. , Behrmann L. A. , Ahrens T. 
Published: December 2007

ABSTRACT
Tests using multi-shot perforating guns in large 3/4 × 3/4 × 9/10 m blocks of stressed rock have been used to quantify stress-induced penetration reductions for three different charges. All three charges were tested in Berea Sandstone, one charge was tested in Bedford Limestone. The fractional reduction in penetration depends on charge design, size and rock type. In tests with elevated pore pressure, data best fit an effective stress law, P(effective) = P(confining) – P(pore). Larger fractional penetration reductions were observed for a small charge (10-cm rock penetration). This may be partially explained by correlating penetration with hoop stress near the wellbore rather than with mean effective stress.
Two methods are considered to predict the observed penetration reductions. First, changes in acoustic velocities with pressure are correlated directly with penetration depths. Thus, log or core data may be useful in predicting downhole penetration. Second, a penetration model that includes the effect of target strength under confining stress is evaluated. The latter theoretical analysis results in a charge-dependent semi-empirical parameter related to impact pressure. The value of this parameter is less for the smaller Charge A than for Charge B. The ability of this simple theory to reproduce observed penetration reductions suggests that a more sophisticated treatment may be able to predict downhole perforator performance directly from the characteristics of a given charge.
Enhanced Recovery of Coalbed Methane through Hydraulic Fracturing
Authors: Holditch S. A. , Ely J. W. , Semmelbeck M. E. , Carter R. H. , Hinkel J. , Jeffrey R. G. 
Published: December 2007

Abstract
Hydraulic fracturing has been used to accelerate removal of methane from coal seams ahead of underground mines. Originally, all of the gas that was produced was flared or vented. Over the past decade, however, there has been a growing awareness of the vast potential for recovery of methane gas from coal seams. This awareness is leading to the commercial exploration and development of coalbed methane reservoirs in many areas of the U.S.
Coalbed methane production is viewed as a new and significant energy source. Associated methane gas from coal is now the primary source of natural gas for the state of Alabama and is rapidly becoming a major source of natural gas in the San Juan Basin of New Mexico and Colorado.1–6 The natural gas industry is still learning how to complete wells and produce gas from coal-seam reservoirs. Compared to our knowledge of techniques for the completion and production of sandstone and limestone reservoirs, our knowledge in coal-seam reservoirs is minimal, at best.
The success achieved in producing gas from shallow coal has encouraged some operators to explore for gas trapped in deep coal seams that will never be mined. One area of significant activity is the San Juan Basin. To optimize recovery from most of the wells drilled into deep coal seams, hydraulic fracturing treatments are required. Experience has shown that the design and execution of fracture treatments in coal seams is not straightforward. High injection pressures, complex fracture systems, screenouts and the production of proppant and coal fines after the treatment are typical problems facing the operator.
Horizontal Drainhole Drilling Techniques Used for Coal Seam Resource Exploitation
Authors: Logan T. L. 
Published: December 2007

ABSTRACT
Methane gas contained in coal represents a potential new gas supply. Transformation of this large gas-in-place resource to reserves will depend on developments of modified and/or new completion methods to achieve long-term economic production. Coal reservoirs typically have very low matrix permeability with gas being desorbed from the matrix to the wellbore through a system of natural fractures or cleats. Due to low permeability, coal reservoirs usually require hydraulic fracture stimulation to achieve economic production. Investigations have shown that hydraulic fractures usually propagate parallel to the maximum stress or face-cleat direction and therefore may not adequately access an anisotropic reservoir. A more effective stimulation technique may be a horizontal borehole placed perpendicular to the maximum permeability direction. This paper discusses the short-radius and medium-radius directional drilling techniques that have been used to successfully place horizontal drainhol es into coal seams.
Insights into Hydraulic Fracturing of a Horizontal Well in a Naturally Fractured Formation
Authors: Layne A. W. , Siriwardane H. J. 
Published: December 2007

Abstract
Horizontal wells are thought to be necessary in formations with low-permeability such as the Devonian shales to increase natural gas recovery and to reduce the risk of drilling a dry hole. In a horizontal well, the bore hole crosses multiple natural fractures in the reservoir. Stimulation data from a 2,000 ft (609.6 m) horizontal well drilled into the Devonian shales in Wayne County, West Virginia, was used in this study. Inflatable packers and casing port collars were used so that individual zones could be tested or stimulated along the wellbore.
This paper focuses on an analysis of hydraulic fracture design and geometry predictions for the above horizontal well. Current hydraulic fracture modeling theories address failure mechanisms and the propagation of a single crack from a vertical wellbore. These theories have been adapted to predict the pressure, flow rate, and induced fracture geometry for each natural fracture intersected by the hydraulic fracturing fluid in the horizontal wellbore. A tubing/annulus flow model was coupled with a hydraulic fracture model that predicts the three-dimensional geometry of multiple natural fractures propagating from a horizontal well. Additionally, a closed-form solution was developed to predict the pressure and flow rate distribution along the lateral extent of the wellbore.
Predicted results were compared with in situ fracture diagnostics from gas (nitrogen and CO2) and foam stimulation treatments. Radioactive-tracer with spectral-gamma-ray logging confirmed that both fluid pressure and stress perpendicular to the fracture affect the injection flow rate distribution along the wellbore. Both of these factors were used as governing mechanisms for fracture geometry predictions in the simulation model. Predictions based on these models and tracer logs confirm that the single crack theory for fracture propagation is not applicable for stimulations that are initiated along an isolated part of a horizontal borehole.
Drainage Study in the Carthage (Cotton Valley) Field
Authors: Schell E. J. 
Published: December 2007

ABSTRACT
The Carthage (Cotton Valley) Field contains many massive low permeability sands and covers over 200,000 acres. The field development occurred in stages, first on 640 acres and later on 320 acre spacing. Union Pacific Resources Company operates approximately 21,000 acres and has been studying the Cotton Valley since early in the field's development. Infill well performance and initial pressure tests indicate that the existing wells' drainage areas are probably less than 182 acres. Numerical simulation on a typical well shows that the drainage area averages 67 acres for all the sands. Infill drilling on a smaller well spacing will be required to effectively and efficiently deplete this reservoir.
Decline Curve Analysis for Multiphase Flow
Authors: Fraim M. L. , Wattenbarger R. A. 
Published: December 2007

ABSTRACTIn this study, the production from a well in a solution-gas drive reservoir with interstitial water flow from the transition zone is converted to a slightly compressible liquid for analysis on current decline type curves. Integral transforms for time, pressure, and rate have been created to linearize the diffusivity equation for multiphase flow for certain reservoir conditions. The integral transform variable is called an ‘equivalent liquid’ variable and it has the same units as the original variable. All the dimensionless definitions using equivalent liquid variables use initial properties.This method concentrates on accounting for the effect of the saturation gradients on the rate-time profile as the bubble point moves out into the reservoir and for the effect of changing fluid properties after late infinite acting flow. The radius of investigation is extended so that it accounts for the change in fluid and rock properties around the wellbore during high rate production periods. This extended definition can be used to calculate the time when boundary dominated flow is seen at the well.‘Pseudo’ relative permeability curves are created for the reservoir drainage volume. We show their shapes will not be similar to the core determined relative permeability curves because the ‘pseudo’ curves include the effects of saturation and capillary pressure gradients.The effects of gravity segregation, capillary pressure, a skin zone, and some types of formation permeability hetergeneities are examined for the pseudo relative permeability curves and the radius of investigation.
A Generalized Approach to Determine Properly any Aquifer Influence Function in an Analytical Form
Authors: Molinard J-R. , Le Bitoux P. , Fasanino G. , Tek M. R. 
Published: December 2007

ABSTRACT
The production-pressure performance of any producing or storage reservoir depends upon the influence exerted by the surrounding aquifer. Such an influence is mathematically represented by an "influence function" which obviously depends upon the specific geometric and reservoir properties, and upon the boundary conditions of the aquifer. With the exception of a few simplified geometries and a homogeneity hypothesis, the influence function is not generally available in analytical form. There have been methods suggested in the literature, however, for the calculation of such influence functions numerically from production-pressure data.
The purpose of this paper is to expose a general method for the determination of an analytical form of the influence function, no matter how complex the geometry and other characteristics of the surrounding aquifer may be. This analytical form, ∑  aie-bit is a finite series of exponential terms of time and is the proper representation of transient flow as well as long-term behavior. The general method proposed here can easily account for complex flow patterns and situations, such as: –heterogeneities of the aquifer zone,–vertical refeeding by drainance, and–a fractured aquifer zone.
In addition, the use of the analytical form of the function requires much less CPU time than the methods developed up until now to deal with transient flows. At last, the paper includes: –validation of the method in cases where known solutions exist (Van Everdingen and Hurst function, f or example).–various real-world applications for 1D or 2D aquifers with different kinds of boundary conditions.–solutions to complex engineering problems using this method.
Numerical Modeling of Gas and Water Injection in a Geologically Complex Volative Oil Reservoir in the Lake Maracaibo Area, Venezuela
Authors: Silva R. J. , Niko H. , van den Bergh J. N. , Sancevic Z. A. 
Published: December 2007

ABSTRACT
MARAVEN S. A., a subsidiary of Petroleos de Venezuela S. A. is operating the majority of Eocene reservoirs in the Maracaibo basin. The CLC, a large volatile oil accumulation of the deep Eocene C, presently undergoing primary depletion, will most likely need additional recovery processes. A multidisciplinary study was therefore carried out within the framework of the Joint Research Agreement between Maraven/Intevep/Shell with the objective of arriving at the best recovery scheme.
The preparatory phase of the study involved process simulations which demonstrated that the vaporising gas drive prevailing under gas injection could be modelled sufficiently accurate using the volatile oil version of a black oil simulator. This was extensively checked by simulations in both 1-D and 2-D, using ternary diagram versions of compositional reservoir simulators. The main problem confronting reservoir simulation in this area is, however, how to realistically describe heterogeneities. The wide well spacing in these Eocene sandstone reservoirs precludes meaningful correlations on a well-to-well scale. Therefore, a probabilistic technique was used to create likely reservoir architectures in the form of detailed 2-D cross-section whilst still honoring measured well data.
The resulting detailed reservoir models were used to simulate likely performance under water and gas injection. Results indicate that water injection is a very safe process, as both capillary and viscous crossflow from highly permeable into tight layers create a rather even flooding profile. On the other hand, gas injection is very sensitive to internal heterogeneities and vertical permeabilities.
Various routes of lumping reservoir properties to arrive at coarser models for large scale field modelling were also attempted. The usefulness has been demonstrated of the concept of dynamic pseudo relative permeabilities/capillary pressures for simplying such complex sandstone reservoir models whilst still maintaining sufficient accuracy.
Prediction of Hydrocarbon Pore Volume With Uncertainties
Authors: Berteig V. , Halvorsen K. B. , Omre H. , Hoff A. K. , Jorde K. , Steinlein O. A. 
Published: December 2007

ABSTRACT
Prediction of the hydrocarbon pore volume with uncertainties provide important support for decisions concerning development of petroleum reservoirs. A stochastic modelling approach is used to obtain improved predictions and uncertainties. Spatial aspects and qualified guesses from the user is included in the model. Consistency with existing wells is ensured. A case-study is presented. The .92 confidence interval is found to be approximately 95% of the average value with one well present and approximately 24% of the average with eight wells present.
Removal and Abandonment: Cost Reduction by Forward Planning
Authors: Carruthers D. R. 
Published: December 2007

ABSTRACT
The paper will show how cost reductions during Removal & Abandonment (R&A) can be achieved by forward planning. The planning will necessitate a greater depth of thought, but will not involve a significant increase in either capital, or operating cost.
Current design and operating practice pay little attention to the problems of eventual removal and abandonment. By recognising the impact of decisions taken during design, installation, and operation on the eventual costs of removal it is possible to modify the actions taken so that, at no increase in cost, the final cost of removal will be reduced.
To illustrate general lines of argument, specific examples are given. These are drawn from both the northern and southern sectors of the North Sea.
The Mechanism of Wettability Alteration Due to Surfactants in Oil-Based Muds
Authors: Menezes J. L. , Yan J. , Sharma M. M. 
Published: December 2007

ABSTRACT
The mechanism for the alteration of sandstone wettability due to interaction with oil-based mud components such as cationic and anionic surfactants is investigated. Extensive use of such surfactants is made in drilling muds and completion fluids. It is shown through contact angle and capillary pressure experiments, that oil-based mud components can in some cases drastically alter the original wettability conditions of both sandstone and carbonate rocks. The wettability alterations are caused mainly by surfactants in the drilling fluids.
Contact angle measurements were made on quartz that had been equilibrated with the oil-based mud components. Additional measurements were made on quartz in the presence of an aqueous solution of the drilling fluid component.
The changes in the measured contact angles are explained on the basis of disjoining pressure concepts. The van der Waals, electrostatic, and structural components are considered. Zeta-potentials on the silica-surfactant solution and oil-surfactant solution interfaces are measured. Contact angles computed using the van der Waals and electrostatic components only are not in agreement with the experimentally measured angles. It is clearly shown that the structural component needs to be accounted for to calculate a theoretical angle that is comparable with the experimental angle. The structural component was found to vary with the concentration of surfactant presumably due to the formation of monolayer and bilayer structures. The results of this study provide a general framework within which wettability alterations caused by surfactants in drilling or completion fluids can be viewed.
Acidizing Fluids Used to Stimulate High Temperature Wells Can Be Inhibited Using Organic Chemicals
Authors: Frenier W. W. 
Published: December 2007

ABSTRACT
In order to protect production tubing from corrosion during acidic stimulation treatments at temperatures above 250°F (121°C), inhibitors containing heavy metals (copper, arsenic or antimony) have been employed. These metallic inhibitors are the subject of increasing regulatory control in the US and abroad. A new inhibitor system containing only organic chemicals (ketones, quinolinium salts and formic acid) now has been developed to protect oilfield tubular goods to temperatures as high as 400°F (204°C) in hydrochloric acid.
This paper will describe the synthesis and testing of a series of pyridinium and quinolinium compounds used as part of an inhibitor package that also contains aromatic ketones and aliphatic acids such as formic acid. Using the corrosion rate of N80 steel as the major descriptor, Quantitative Structure-Activity Relationships (QUSAR) were constructed. Based on such relationships, the structure of the quat component was optimized, and an experimental formulation was devised. This Experimental High Temperature Acid Inhibitor (EXHTI) was then tested in a variety of acidizing fluids in contact with carbon and alloy steels at temperatures to 400°F (204°C).
Adsorption and Desorption Characteristics of Mineral Scale Inhibitors as Related to the Design of Squeeze Treatments
Authors: Przybylinski J. L. 
Published: December 2007

Abstract
Five structurally different scale inhibitors were studied using a kinetic adsorption-desorption technique. Adsorption was fast. All inhibitors adsorbed to a similar degree. Desorption was slow. There were large differences in the degree to which different inhibitors desorbed. The kinetic desorption characteristics are more important in picking an appropriate squeeze chemical than are the adsorption characteristics.
The study realistically modeled the flow rate, contact time and brine composition that might be found in an oilfield reservoir. Adsorption was measured on limestone at 40°C and sand at 40°C and 80°C. The inhibitors were diethylenetriamine pentamethylenephosphonic acid, hydroxyethylidene diphosphonic acid, a triethanolamine phosphate ester, a polyacrylic acid, and a polymeric phosphonate inhibitor.