bluuebunny/crossref_metadata_2025_split huggingface dataset:
Investigation of Changes in the Structure of Clays During Hydrothermal Study of Drilling Fluids
Authors: Carney Leroy L. , Guven Necip 
Published: December 2007

AbstractThe need for a drilling fluid that will exhibit its basic requirements at temperature levels high enough to be used for geothermal drilling has prompted studies of various systems.1 The temperature range of some of these studies has been between ambient temperature and 700°F (370°C). A system was developed that exhibited the desirable properties of a good drilling fluid system at elevated temperatures and pressures. A fluid that exhibited these desirable properties after being subjected to high temperature and pressure was unusual as compared with presently used fluids. Therefore, investigation into why these fluids were capable of exhibiting good rheology and fluid-loss control was conducted. It was found that certain mineralogical components of the drilling fluid undergo transformation after being subjected to high temperatures and pressures. The conversion is temperature dependent but also is affected by the presence of various salts as well as the presence of silica and calcium.The fluids under investigation contained the mineral sepiolite as the basic ingredient. The changes in the sepiolite are reported in this paper.
Capturing Reservoir Behavior by Simulating Vertical Fracture and Super-K Zones in the Ghawar Field
Authors: Phelps Robert E. , Strauss Jonathan P. 
Published: December 2007

Summary
A dynamic simulation model containing several million cells shows geological details used to simulate the vertical fractures and high stratiform permeability of the Ghawar field. Observed performance data have shown that well intersections in the Ghawar field exhibit thin intervals of extremely high productivity. These can be related to high-permeability layers (stratiform features) or to subvertical faults and fractures. To capture observed field behavior in a dynamic simulation model, these two features must be incorporated in the simulation model. This paper discusses how vertical fractures and high stratiform permeability were simulated in the world's largest oil reservoir.
A Comparison of Caustic Soda and Soda Ash as Chemical Media for SO2 Recovery in Oilfield Steam Generators
Authors: Reyes R.B. , Siemak J.B. 
Published: December 2007

Caustic soda and soda ash were used as alkalinity sources in the liquid scrubbing of SO2 in flue gases produced from crude-oil-fired steam generators used in thermally enhanced oil recovery. Caustic soda was used more efficiently, allowing the SO2 scrubber to run at a lower pH with a higher SO2 removal capacity. Overall economics favored the use of caustic soda over soda ash.

Introduction
This study compares caustic soda with soda ash for scrubbing sulfur dioxide in flue gas streams from stream generators used in thermally enhanced oil recovery. The data apply to many other applications as well. Reaction products were measured, and the scrubber chemistry was identified. Mass balances were made by varying chemical feed rates to determine SO2 recovery efficiencies and economics.While distinct differences were observed between caustic soda and soda ash, both the SO2 recovery and the economics favor the use of caustic soda, even though its cost per pound is greater. This is attributable primarily to differences in chemical-reaction kinetics and handling characteristics of the two chemicals.

Scrubber Chemistry
On a purely stoichiometric basis, 1 lbm caustic soda is equivalent in alkalinity to 1.33 lbm soda ash. However, observed chemical consumption rates are nonstoichiometric. In reality, more than 2 lbm soda ash are necessary to do the job of 1 lbm caustic. To understand this phenomenon, scrubber chemistry must be analyzed.
Reactions in a system using a aqueous medium to scrub SO2 from flue gases, alkali must be added to maintain the desired degree of SO2 removal. At the point of alkali addition, several reactions can occur, depending on which alkali is used. A simplified overview of these reactions would be
NaOHSO2 ---- Na2SO3, NaHSO3,....................(1)
and
Na3CO3SO2-------- Na2SO3, NaHSO3, CO2.............(2)
In reality, the chemistry and much more complex. The actual scrubbing, or SO2 removal, is carried out with ionic species formed from the above highly soluble sodium salts.The chemistry of scrubbing and the ionic species present depend on which alkali is used. Once the present depend on which alkali is used. Once the alkali enters the scrubbing system, it reacts quickly according to Ionic Reactions 3 or 4, depending on whether caustic soda or soda ash is used:
Caustic Soda OH + HSO3 -----------&gt;SO3 = + H20.......(3)
Soda AshCO3 =+2HSO3 -----------&gt;2SO3 = +CO2 ......(4)
JPT
P. 751
Linear Aquifer Behavior
Authors: Nabor G.W. , Barham R.H. 
Published: December 2007

Introduction
Linear aquifers, either limited or essentially infinite, may be encountered in reservoir engineering practice. In areas where faulting fixes reservoir boundaries, the fault block reservoir may have an aquifer of limited extent whose geometry is best approximated as linear. An infinite linear aquifer can occur as a regional feature whenever water movement through the aquifer member is constrained to one direction. Such constraints can arise from major faults. facies changes or pinchout of the member.
Miller* pointed out that linear aquifers have received only meager attention in the past. He analyzed the performance of finite and infinite aquifers, developed working equations and curves, and presented examples. While Miller's curves may be used fairly easily, a separate one is required for each size of aquifer. In this paper, Miller's equations have been used as a starting point. By modifying them slightly, they can be reduced to a form which yields a single a working curve, applicable to any size of aquifer. Thus, interpolation between curves is eliminated and accuracy is improved.
Miller's results for finite aquifers covered only the boundary condition of no flow across the outer aquifer boundary. This paper also includes the case of constant pressure at the outer aquifer boundary.
DEVELOPMENT OF EQUATIONS FOR LINEAR AQUIFERS
Miller's equations give pressure drop or cumulative influx at the linear aquifer-reservoir boundary as a function of time for the boundary conditions of an infinite aquifer and a finite aquifer with sealed outer boundary. In addition to these equations, those appropriate for the boundary condition of a finite aquifer with constant pressure at the outer boundary have been developed. The approach used in developing these equations was the same as that used by Miller.
BOUNDARY CONDITION 1: CONSTANT RATE OF INFLUX ACROSS AQUIFER-RESERVOIR BOUNDARY
Infinite Linear Aquifer
(1)
Finite Linear Aquifer, Constant Pressure at Outer Boundary
(2)
BOUNDARY CONDITION 2: CONSTANT PRESSURE AT AQUIFER-RESERVOIR BOUNDARY
Infinite Linear Aquifer
(4)
Finite Linear Aquifer, Sealed Outer Boundary
(5)
Finite Linear Aquifer, Constant Pressure at Outer Boundary
(6)
These equations are usually put in a form where dimensionless time is defined by
(7)
Here, x is a reference distance and is usually taken to be a unit distance. However, the choice is really arbitrary, as long as consistency is maintained. We choose x = L; then
(8)
For finite aquifers, L is the length of aquifer; for infinite cases, it may be considered as an arbitrarily chosen length. The reason for this choice will be clear later when the performances of finite and infinite aquifers are compared.
JPT
P. 561ˆ
Integrated Fractured Reservoir Characterization: A Case Study in a North Africa Field
Authors: Gauthier B.D.M. , Garcia M. , Daniel J.-M. 
Published: December 2007

SummaryIn fractured reservoirs, data directly related to fractures are scarce and 1D (e.g., core and image-log data). Other types of data are more widespread (e.g., seismic data) but generally are related only indirectly to fracture distribution. In such reservoirs, it is necessary to understand and then to model the fracture network on a field-wide scale by integrating all available data.We propose a methodology to achieve this objective. The methodology establishes relationships between the fracturing and other sources of data in a systematic workflow that goes from static 1D data to a 3D dynamic model. The methodology is described and illustrated with a case study from north Africa. In this field, fracture data from image logs and cores are related to (1) 3D seismic attributes (e.g., amplitude, coherency), (2) fault patterns, and (3) other types of well data (e.g., interval thickness, lithology index, and porosity). Production data also are used to quantify the contribution of each fracture set to flow, which then can be mapped on a reservoir basis with the more widely distributed log and seismic data. The resultant set of maps then is entered into a dynamic reservoir model. The methodology has been validated with a new well, the fracture network of which was accurately predicted in the reservoir by the model.
Active Feedback Control as a Solution to Severe Slugging
Authors: Havre Kjetil , Dalsmo Morten 
Published: December 2007

SummarySevere slugging in multiphase pipelines can cause serious and troublesome operational problems for downstream receiving production facilities. Recent results demonstrating the feasibility and the potential of applying dynamic feedback control to unstable multiphase flow like severe slugging and casing heading have been published.1–5 This paper summarizes our findings on terrain-induced slug flow.5 Results from field tests as well as those from dynamic multiphase flow simulations are presented. The simulations were performed with the pipeline code OLGA2000.*The controllers applied to all of these cases aim to stabilize the flow conditions by applying feedback control rather than coping with slug flow in the downstream processing unit. The results from simulations with feedback control show stable process conditions at both the pipeline inlet and outlet in all cases, whereas without control, severe slug flow is experienced. Pipeline profile plots of the liquid volume fraction through a typical slug flow cycle are compared against corresponding plots with feedback control applied. The comparison is used to justify the internal stability of the pipeline. In many cases, feedback control enables a reduced pipeline inlet pressure, which, again, means an increased production rate.This paper summarizes the experience gained with active feedback control applied to severe slugging. The focus is on extracting similarities and differences between the cases. The main contribution is demonstrating that dynamic feedback control can be a solution to the severe slugging problem.
Analysis of Shallow Gas Development From Low-Permeability Reservoirs of Late Cretaceous Age, Bowdoin Dome Area
Authors: Nydegger Gary L. , Rice Dudley D. , Brown Charles A. 
Published: December 2007

Natural gas is being developed and produced in the Bowdoin Dome area from shallow, low-pressure, low-permeability reservoirs that were previously noncommercial. Reservoirs are dominantly thin, discontinuous, shaly siltstone and sandstone laminae and beds which cannot be distinguished on conventional logs. They require stimulation to provide commercial flow rates and necessitate more sophisticated evaluation methods than do conventional reservoirs.

Introduction
This paper reviews the geologic, technological, and economic parameters that have contributed to the development of natural gas reserves in the recently expanded portions of the Bowdoin Dome area. The technology and methods discussed are those used by Midlands Gas Corp., a subsidiary of Kansas-Nebraska Natural Gas Co. Inc, and may differ from those of other operators in the area. The Bowdoin Dome is a very large structural uplift located in eastern Phillips and western Valley counties in north-central Montana (Fig. 1). Natural gas was first discovered on the structure in 1913 in a shallow well drilled for water. The central part of the structure was developed through the 1950's with natural openhole completions in wells drilled where the pay zones are shallower. With the advent of improved completion techniques and increased gas prices in the 1970's, the field was expanded in size to more than 600 sq miles (1550 km2). Natural gas is being produced from low-permeability, low-pressure reservoirs at depths less than 2,000 ft (610 m). The pay zones consist of thin, discontinuous laminae and beds of siltstone and sandstone, and a more persistent limestone bed. These beds are enclosed in a thick sequence of offshore marine shale of late Cretaceous age. The gas is of biogenic origin and was generated in the surrounding marine shales. One major problem existed with the most recent expansion. The development program was designed to be run concurrently with the construction of a large gathering facility. The purpose was to increase economic viability and to develop a more efficient optimization of stimulation techniques and spacing criteria. However, delays in the approval of the pipeline facility forced the operators to use technology evolved in other areas. Specifically, the development of similar shallow gas accumulations in southeastern Alberta was used as an analog for the original treatment designs and 640-acre (2.6 x 10(6) m2) spacing. Most of the development in the Bowdoin Dome area was completed before the final construction of a gathering facility. Therefore, information on the adequacy of the initial development design has become available only recently.

Structure
The Bowdoin Dome is a very large, nearly oval arch which has structural closure of about 700 ft (200 m) on top of the Upper Cretaceous Greenhorn lime. Most of the new development concentrates on a north/northwest-trending nose that extends across the Canadian border.
Convection, Dispersion, and Adsorption of Surfactants in Porous Media
Authors: Ramirez W. Fred , Shuler Patrick J. , Francois Friedman 
Published: December 2007

Abstract
Using the theory of volume averaging, we have shown1 that molecular diffusion, mass tortuosity, and mechanical mixing contribute to the mass-dispersion coefficient. A series of experiments were conducted on the system Triton X-100TM surfactant, n-decane oil, and water to determine the contribution of each mechanism to the total-dispersion matrix for flow through fired Berea sandstone. The dynamics of adsorption and the effect of dead-space volume are considered for the single-phase transport of surfactant through fired Berea. A new dynamic asdorption model is developed which considers both mass transfer to the fluid/solid surface and a kinetic surface-adsorption mechanism. Both kinetic adsorption and mass-transfer rate mechanisms are shown to be important over a wide range of injection rates.
Geomechanical and Decision Analyses for Mitigating Compaction-Related Casing Damage
Authors: Bruno Michael S. 
Published: December 2007

Summary
Reservoir compaction and its associated bedding plane slip and overburden shear have induced damage to hundreds of wells in oil and gas fields throughout the world. Critical casing damage mechanisms observed in a variety of structural settings include overburden shear damage on localized horizontal planes, shearing at the top of production and injection intervals, and compression and buckling damage within the production interval, primarily around perforations.
Analytical solutions are readily available to estimate compaction, subsidence, and casing damage risks. These should be applied as initial screening tools at an early stage in reservoir development planning. They also can be applied to estimate relative risks for various well locations and trajectories.
Geomechanical models of increasing complexity, including 2D and 3D finite element type techniques, have been used with good success to assess formation deformation and casing damage risks in several reservoirs and are described herein. Three-dimensional geomechanical models at the wellbore scale are required to evaluate shearing deformation on specific well designs and are used to assess damage mitigation effectiveness for varying completion strategies.
An economic decision tree model is applied to compare the costs and benefits of alternative well designs while taking into account inherent uncertainties in model input data, the well's damage location, and the effectiveness of various mitigation strategies. In some instances, the appropriate action is not to change the completion design, but simply to accept damage risk.
A Laboratory Study of the Effects of CO2 Injection Sequence on Tertiary Oil Recovery
Authors: Wang George C. , Locke C. David 
Published: December 2007

Abstract
The major reason that CO2 stands out as a fluid displacement agent for enhanced oil recovery is because of the adaptability and relatively low cost of CO2 compared with other chemical flooding agents. CO2 miscible displacement could be achieved for a wide spectrum of reservoir oils through an extraction/vaporization process. Even under immiscible reservoir conditions, incremental oil recovery still can be obtained by simple viscosity reduction and swelling of crude oil. Among other desirable properties of CO2 is its high density. At typical reservoir conditions, CO2 is nearly as heavy as reservoir oil; thus, the problem of overriding common to most gas injecting systems could be minimized greatly.
In spite of all the advantages of CO2 process, it inherits the disadvantage of high mobility ratio so that the CO2 has a great tendency to channel through the oil, bypassing much of the oil in the reservoir. To alleviate the difficulties, a technique consisting of alternately injecting small CO2 and water slugs has been applied in field tests.1 The injected water interferes with the flow of CO2 to minimize the chance of premature CO2 breakthrough.
Another technique, called "programmed slug," has long been applied in polymer flooding to prevent deleterious effects of viscous fingering. More recently, Claridge2 has developed a method for designing graded banks for both polymer and miscible flooding. His study indicates that the use of a graded slug often results in improvement of oil recovery and/or economic attractiveness.
Quantitative Analysis of Drag Reduction in Horizontal Slug Flow
Authors: Daas M. , Kang C. , Jepson W.P. 
Published: December 2007

Summary
Calculations have been made to predict the components of pressure drop in slug flow. This analysis is aimed at understanding, in a quantitative manner, the contributions of both frictional and accelerational components to total pressure drop in horizontal slug flow and the effect of drag reducing agents (DRAs) on each component. Experimental results were in good agreement with predicted values.
The DRA used in this study was effective in reducing both components of the pressure drop. The accelerational component was found to be dominant and formed more than 80% of the total pressure drop. It increased dramatically with increasing superficial gas velocity. With the addition of 20 ppm DRA, the accelerational and frictional components were noticed to decrease by a factor of 70%. At DRA concentration of 50 ppm, they decreased by a factor of 80%. Total drag reduction was found to generally decrease at higher superficial gas velocities.
In sharp contrast with expectations, the drag reduction was recovered mainly from the accelerational component, indicating that the DRA worked not only in the buffer zone but also in the mixing zone in the slug body. The accelerational drag reduction reached values as high as 89% of total drag reduction.
A Comprehensive Wellbore Steam/Water Flow Model for Steam Injection and Geothermal Applications
Authors: Ali S. M. Farouq 
Published: December 2007

Abstract
A comprehensive mathematical model was developed to simulate the downward or upward flow of a steam/water mixture in a well. Comparisons of model predictions with actual field data for both steam injection for oil recovery and geothermal production showed the validity of the model.
The proposed model is based on mass and momentum balances in the wellbore and on heat balance in the wellbore and the surrounding media. Unlike the previous models, the pressure calculation accounts for slip and the prevailing flow regime, based on noted correlations. Furthermore, heat loss to the surrounding formations is treated rigorously. The overall heat transfer coefficient involved permits the consideration of a variety of well completions.
The model was employed for a series of tests to evaluate the effects of the injection pressure, injection rate, time, and well completion on the downhole steam pressure and quality. It was found that the slip concept and the flow regime are essential elements in wellbore steam/water flow calculations. Pressure drop was found to increase with a decrease in the injection pressure, as also with more obvious parameters. An increase in the injection pressure or tubing size and/or a decrease in the injection rate led to a decrease in steam quality at a given depth.
Pressure Buildup Analysis for a Well Produced at Constant Bottomhole Pressure
Authors: Uraiet A.A. , Rajagopal Raghavan 
Published: December 2007

This paper presents procedures to analyze the pressure buildup behavior at a well produced at a constant pressure. Introduction Pressure buildup analyses generally assume that the well produces either at a constant surface rate or at a series of discrete constant rates prior to shut-in. To our knowledge, only Clegg1 has attempted to analyze by conventional semilog techniques2 the buildup behavior of a well produced at a constant wellbore pressure. The lack of research efforts in this area of pressure analysis is not due to the lack of the importance of the problem or the lack of application to petroleum engineering; it is mainly due to the difficulty of obtaining a simple analytical expression to describe the bottomhole pressure buildup behavior at a well, subsequent to production at a constant pressure. The mathematical problem stems from the difficulty of handling the change in the inner boundary condition when the flowing well is shutin - i.e., changing the Dirichlet condition to a Neumann condition. This problem does not occur in the constant-flow-rate case, since the pressure buildup equations can be obtained directly by using the principle of superposition. In fact, the requirement that a well be produced at a constant rate prior to shut-in is imposed by theoretical considerations.
Our objective is to suggest simple procedures to analyze the pressure buildup behavior at a well producing at a constant flowing pressure similar to those used for the constant-flow-rate case.
To date, this type of problem usually is solved by treating the continuous change in rate as a sequence of discrete (step-function) rate changes and then applying the principle of superposition.4,5 This is a tedious and cumbersome procedure, and data often are not available for this type of analysis.
The approach taken here is to follow a generalized procedure similar to the one suggested by Ramey and Cobb6 for the constant-flow-rate case. We obtain pressure buildup data, graph data along conventional lines, and seek simple interpretive rules to analyze these data. We avoid restrictions on producing time which commonly are employed in the classic developments2,3 and do not require that the well be produced at a constant rate prior to shut-in.
This work is a study of pressure behavior during the buildup period. It includes the examination of the effects of producing time prior to buildup, the nature of the outer boundary condition (closed and constant-pressure drive), damage (or stimulation) around the well, and well bore storage. It also includes the analysis of interference data due to the closing in of the producing well.
All the results in this study were obtained by a numerical (finite difference) model.
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