bluuebunny/crossref_metadata_2025_split huggingface dataset:
Horizontal Drilling Enhances Production of Austin Chalk Well
Authors: Slayton R. J. , Peach S. R. 
Published: December 2007

ABSTRACT
TheG. W. Hatch No. 1 Well in Pearsall Field, Dimmit County, Texas, was proposed to achieve horizontal penetration in the Austin Chalk formation. Pinnacle Royalty and Operating Company, Inc. (PROCO), the independent operator of the well, elected a conservative long-radius approach that allowed the use of steerable positive-displacement motors (PDMs). The use of steerable motors resulted in a smooth wellbore, relatively low torque and drag forces while drilling the horizontal reach section of the well, and the ability to steer the wellbore to total depth.
Casing was set after the. first build section was completed into the top of the Austin Chalk formation in order to minimize hole problems and permit handling of any anticipated well kicks.
The 1253-ft horizontal section, drilled in underbalanced conditions, positively identified producing fracture systems while minimizing the formation damage that typically results from ongoing drilling operations.
Drilling continued horizontally in an underbalanced state, although occasional flowing conditions did occur, using both rotary and slide modes of steerable drilling.
Special surface production systems were utilized to handle well flow during drilling operations. The design and field operations of this equipment were critical to the safety and success of the project. Detailed planning prevented problems during actual operations.
Initial tests indicate production rates of 1600 bopd, a significant increase in production from adjacent vertical wells, making the G. W. Hatch No. 1 an economically viable project.
Pore Pressure Analysis Indicates Abnormal Pressure as Reason for Shale Instability in Offshore California Field
Authors: Barron J. G. , Weakley R. R. , Haas M. A. 
Published: December 2007

ABSTRACT
A pore pressure analysis was conducted for an offshore California field which indicated that abnormal pressure in a shale section was the reason for hole instability problems in this area. Previously, the common belief was that the chemical reactivity of the shale caused the instability.
The wells were encountering a thick shale section which caused considerable drilling problems due to sloughing shale and eventual stuck pipe. The shale section was sandwiched between two permeable intervals that were normally pressured. The question presented was: Can a thick shale section be abnormally pressured even though normally pressured formation lie just above and below?
This paper illustrates a technique of creating a pore pressure overlay for the general geographic area to determine if the shale section could be abnormally pressured. Since conclusive abnormal pressure data from the subject area did not exist, known abnormal pressure data from a nearby field was used for the pore pressure overlay development. The similarity in the overburden gradients and depositional environment between the two fields is what made this analysis feasible.
The pore pressure analysis clearly defined the thick shale section as being abnormally pressured. Based on the predicted pore pressure schedule, mud weights in the subsequent well were increased and the well was drilled to TD without problems. The shale instability problems, which had plagued this field In the past, were not evident.
Simulation of a Single-Well Injection/Production Steamflood (SWIPS) Process in an Athabasca Tar Sand
Authors: Duerksen J. H. 
Published: December 2007

ABSTRACT
The simulation of a single-well injection/production steamflood (SWIPS) process in an 80 ft (24 m) thick Athabasca tar sand shows a favorable production response from a 152 ft (46 m) drainage radius (1.67 acre or 6,757 m2 well spacing) at a depth of 450 ft (137 m). After 10 years of steam injection, cumulative bitumen production and steam/oil ratio were: (1) 192,800 bbls or 30,650 m3 (62.8% of OOIP) and 3.8 for a homogeneous reservoir; (2) 134,300 bbl or 21,350 m3 (46.6% of OOIP) and 4.4 for a heterogeneous reservoir; (3) 130,680 bbl or 20,780 m3 (45.4% of OOIP) and 4.1 for a heterogeneous reservoir with vertical permeability constraints; and (4) 125,900 bbl or 20,020 m3 (46.8% of OOIP) and 4.7 for a heterogeneous reservoir with a 5-ft (1.5 m) bottom water layer. The application of the process at shallower depths (150 ft or 45.7 m) just beyond the maximum depth for surface mining is limited by the constraints on steam injection pressure and temperature. The best predicted performance with the producer pumped off was 46,660 bbl or 7,420 m3 of bitumen (15.2% of original oil in place (OOIP)) and a steam/oil ratio of 3.6 after 10 years of steam injection.
Evaluation and Treatment of Organic and Inorganic Deposition in the Midway Sunset Field, Kern County, California
Authors: Bilden D. M. , Efthin F. P. , Garner J. J. , Pence T. C. , Kovacevich S. T. 
Published: December 2007

ABSTRACT
The Midway Sunset Field is the 2nd largest oil producing-field in the state of California. Current production is approximately 155,000 barrels of oil per day -from 9,200 wells. Due to variable productivity exhibited by wells in this field, an extensive study was conducted to determine potential production impairment mechanisms. This study was accomplished by analyzing cores, produced fluids and the organic deposition found in and around the slots of liners pulled from two wells.
The reduced productivity exhibited by these wells was determined to be due primarily to the deposition of organic and inorganic components in the liner slots. This deposition can be associated with the asphaltic properties of the crude, the unconsolidated nature of the formations and the use of Thermal Enhanced Oil Recovery techniques. Quantitative and qualitative studies were performed to evaluate the damage and generate an operationally feasible and cost effective treatment. This investigation resulted in the design of a unique treatment and placement technique.
Production response is presented from 35 wells included in this ongoing stimulation program. Candidate selection criteria and related stimulation performance are also discussed.
Quality Control Assures Successful In-Situ Internal Pipeline Coating Operation: A Case History
Authors: Hagood D. S. , Choate L. C. 
Published: December 2007

Abstract
In situ applied internal pipeline coatings are used to control internal corrosion, rehabilitate existing pipelines and improve flow efficiency. Internal coatings are applied to product pipelines, flowlines, water injection lines and any other lines that are subject to internal corrosion. Internal coating operations originated in the 1940&#39;s and have been performed until the present with varying degrees of success. present with varying degrees of success. Although improvements have been made in the coatings as well as in cleaning and application procedures, quality control is recognized as the primary factor determining the success or failure of an in situ internal coating operation. This paper describes the quality control procedures and equipment which were recently employed to insure the successful coating of a 4-inch, 14,000 foot sour service flowline in Tunisia, North Africa.
Quality control procedures were applied from initial pipeline design through the construction and coating phases of the project. The measures implemented are listed project. The measures implemented are listed and described below as they were applied either pre-construction or post-construction.
PRE-CONSTRUCTION PRE-CONSTRUCTION 1. The pipeline was designed for ease of pigging.
In situ internal coating operations rely on the use of multiple pig trains to clean, dry and coat the pipe wall; therefore, it was necessary to design the flowline for ease of pigging. The flowline diameter was held constant while sharp bends and changes in elevation were avoided. A bend radius of five pipe diameters was utilized.
2. Mill applied coatings were avoided.
No mill varnish or oil was applied to the internal or external pipe wall after manufacture. Any coating intentionally or inadvertently applied to the inner pipe wall would require removal prior to coating.
3. The proposed coating was tested for suitability to the expected service.
The coating to be used was tested under the anticipated operating conditions to verify its suitability. Adhesion and resistance to abrasion were the primary concerns.
POST-CONSTRUCTION POST-CONSTRUCTION An internal coating operation consists of cleaning, drying and coating the pipe wall. A portable laboratory was mobilized to the work location in order to adequately monitor the critical parameters as discussed below. An inventory of the equipment in the portable laboratory is included as Attachment 1.
1. The chloride levels of the cleaning and rinsing water were monitored.
Chloride levels in excess of 400 ppm will have a tendency to cause coating disbondment; therefore, it was imperative to monitor the chloride levels in the water used for cleaning and rinsing the flowline prior to coating. The chloride content was determined by mercuric nitrite titration using a Hach Digital Titrator Model CD-DT.
2. The pipe was inspected for cleanliness prior to coating.
P. 596
Saturation Evaluation of Secondary Recovered Reservoirs
Authors: Hashem M. N. 
Published: December 2007

ABSTRACT
Consider the case of a sand stone reservoir that has been under a water or steam flooding program, that was not efficient. A lot of effort is currently being done to evaluate and recover the oil that was left in the ground. As the flood fluid has now been introduced to the Reservoir element, it becomes very difficult to find the value of the water saturation as the salinity of the flood water is different from the original formation water, and involves a lot of coring and other expensive operations to come up with the value of Sw; water saturation.
The technique suggested in this paper finds the value of the saturation using logs, both old and new, that are available for that field, the old being the original resistivity logs and the new being the logs of the new well drilled and recorded after the flood.
This technique agrees very well with the saturation obtained by other methods including other logs such as the EPT log, and the core analysis results, within a tolerance of ± 7%.
Successful Installation of a Gas-Gathering System in a Waterflood Environment: North Riley Unit
Authors: Pietsch C. E. 
Published: December 2007

ABSTRACT
Casinghead gas gathering systems are generally limited to low pressure reservoirs; however, they may also be used successfully in reservoirs under pressure maintenance. This paper discusses the theory, design, and results of an 82 well gas gathering system at the North Riley Unit, a Clear Fork reservoir under waterflood operations. The design of the system includes: 1) sizing the gathering lines, 2) isolating portions of the system, 3) modifying existing production wellheads, and 4) locating possible areas of liquid accumulations. Gas gathering has resulted in lower operating pressures of surface facilities, increased oil production, and increased downhole pump efficiency.
Using Short-Term Pressure Buildup Tests To Calculate Gas Reservoirs
Authors: Vu T. , Chen H. Y. , Poston S. W. 
Published: December 2007

Summary
Static reservoir pressures are required for all gas material balance calculations. There are no techniques currently available for using isochronal, transient pressure buildup tests to estimate original gas in place.
A method to extrapolate the slope of a line generated from two or more isochronal or short-term pressure buildup tests to initial conditions to estimate gas reserves has been developed. Simulation as well as theoretical studies prove the technique may be applied to gas reservoirs with a permeability of one md or greater. However, the extrapolations become skewed for gas reservoirs displaying a permeability of less than one md. The isochronal test method may not be used with a high degree of accuracy for these low permeability reservoirs. The divergence of the extrapolations was found to be caused by the μc product term evaluated at a subsequent pressure differing significantly from the pc product term evaluated at static conditions. This pressure drawdown effect was found to only be significant in reservoirs displaying a permeability of less than 1 md.
Analysis of the fundamental concepts has formulated a relationship between the diffusivity equation and the material balance equation to account for changing fluid properties during pressure buildup. A method has been developed from these relationships to adjust the real time isochronal interval for the changing gas fluid properties. The adjustment technique permits the transient pressure, isochronal method to be applied to very low permeability reservoirs as long as the pressure is 1,000 psia or greater.
The Determination of the Static and Dynamic Properties of Nitrified Cements
Authors: Mueller D. T. , Franklin V. L. , Daulton D. J. 
Published: December 2007

ABSTRACT
The process of foaming oil well cements entails the injection of a known quantity of nitrogen gas into a given volume of cement slurry and foaming agent. The amount of nitrogen injected at surface, to produce a foamed cement of a desired density in situ, is a function of the temperature and pressure conditions in the annulus where the slurry will reside when pumping ceases.
Pressure and temperature variations between the point of injection of nitrogen into the slurry and its final annular location create a system that will fluctuate in density, viscosity, volume, and rate depending on the downhole conditions at the moment of observation. This inherent variability in the gas fraction (quality) of a nitrified cement is an important engineering consideration since formations will be exposed to fluids whose dynamic properties are different than those anticipated when in place. These variances can profoundly impact the success of the cementing operation.
Mathematical solutions originally developed for foam fracturing treatments have been applied to nitrified cements. This paper provides a method of quantifying the dynamic and static properties of a nitrified cement at any point in its pumping history.
Breaker Concentrations Required To Improve the Permeability of Proppant Packs Damaged by Concentrated Linear and Borate-Crosslinked Fracturing Fluids
Authors: Brannon H. D. , Pulsinelli R. J. 
Published: December 2007

ABSTRACT
The permeability of proppant-packs may be significantly damaged by the gelling agents used in hydraulic fracturing fluids. Several recent fracture conductivity studies have sought to quantify the damage caused by common fracturing fluids over a wide range of downhole conditions. However, viable approaches to reducing the proppant-pack permeability damage caused by these fluids have rarely been discussed.
Oxidative breakers have been well documented as being useful for degrading the viscosity of hydraulic fracturing fluids. Degrading the fluid to a non-viscous state was long thought to provide sufficient polymer degradation to minimize the proppant-pack permeability damage. Recent studies have illustrated that the permeability is significantly impaired by the concentrated polymer residue even though sufficient breaker concentrations have been added to effectively reduce the fluid viscosity.
This study is concerned with the determination of the concentrations of an oxidative breaker which are required to significantly reduce the proppant-pack permeability damage caused by concentrated aqueous hydraulic fracturing fluids. Long-term proppant-pack permeability testing was performed using a modified API-type fracture conductivity cell which permitted fluid loss through two low-permeability cores. The fluids which were evaluated were linear and crosslinked gels of natural guar and hydroxypropyl guar (HPG). The effective polymer concentrations were varied from 100 to 440 Ib/Mgal to account for concentration due to fluid-loss.
Test results indicate that elevated breaker concentrations can very effectively reduce proppant-pack permeability damage. The breaker concentrations required to show significant reduction in permeability damage were found to be strongly dependent upon the polymer concentration and the presence of crosslinker. An understanding of the relationships of these parameters and the resultant retained proppant-pack permeability can be very useful in the design of fracturing treatments or the prediction of well performance.
Pressure Transient Behavior of Vertically Fractured Wells in a Closed Square Multilayered Reservoir
Authors: Okoye C. U. , Oshinuga A. D. , Ghalambor A. 
Published: December 2007

ABSTRACT
This study presents the application of a new analytical model for analyzing pressure transient data for wells intercepted by a finite-conductivity vertical fracture in a closed square multilayered reservoir using the concept of a dual-porosity system. The solution takes into account the effect of wellbore storage. Our specific objectives are twofolded: first, to estimate fracture half-length, fracture conductivity and to correlate multilayered (two-layered) solution with the single-layer solution; secondly, to verify the numerical solution with the analytical solution. A set of asymptotic analytical (early-, intermediate-and late-time) solutions is also presented.
In addition, we developed constant rate drawdown type curves applicable for analyzing transient pressure data. These type curves are used to match drawdown and buildup curves to determine fracture half-length, reservoir permeability and fracture conductivity. The results obtained from our type curves indicate that if the reservoir conductivity is known or can be calculated from given data, the estimated values of the aforementioned parameters compared favorably with the value? of the designed parameter.
Although this study presents the solution to a twolayered system, it can be extended to a n-layered reservoir system.
Evaluation of Steam Resistance of Gravel Packing Material
Authors: Weaver J. , Knox J. 
Published: December 2007

Abstract
Carefully sized sand has been used for gravel packing for many years. With the advent of steam flooding it was observed that the pack sand disappeared from the well, The realization that sand was soluble in hot water gave rise to several studies which evaluated this problem, Common proppants and other materials were evaluated but no viable packing material was found.
This study compared the available packing material by flowing low quality steam through a cell containing the gravel. Ionic composition and concentration of the effluent were monitored throughout the flow tests. These data gave an indication of the mechanism of certain types of deterioration. Weight loss of the gravel with respect to flow volume was determined for each material. Micrographs of the packing material before and after the tests indicated that weight loss data was not sufficient for the selection of the preferred material.
Most of the aluminum oxide based materials were found to selectively dissolve and reprecipitate, forming potential permeability damaging fines. While much of the gravel remained, the fines were responsible for reducing the permeability of the pack. In some cases the test cell was plugged. Some of these fines are identified.
Several materials which are not commonly available as proppants were evaluated. One was found to withstand the harsh conditions of the hot water flow test with minimal weight loss and no fines formation. This material is now being evaluated as a gravel packing material in field trials.
It is readily available and inexpensive compared to the aluminum oxide materials. Acid solubility and crush resistance are similar to Ottawa sand but is slightly more angular.
This paper presents detailed results of the laboratory testing of the packing materials including photomicrographys before and after testing. Field results available will also be included.
Strength, Volume and Weight Loss of Gravels and Proppants Due to HF-Based Acids
Authors: Roberts S. S. , Binder M. S. , Lane R. H. 
Published: December 2007

AbstractAcidization by HF-containing acids can drastically reduce both the physical strength of synthetic ceramic proppants and the permeability of gravel packs and propped fractures that utilize these materials. The strength of most acidized ceramics will decrease at a rate faster than implied by weight loss. It is therefore misleading to use weight loss as a measure of stability of ceramic proppants to HF-containing acid. Even seemingly mild acid treatments (low temperature and closure stresses) can have a negative impact on proppant strength and performance. Laboratory measurements on proppant acidized with HCl/HF acid at 176°F (80°C) and 64°F (18°C) verify major strength losses of synthetic proppants even under mild temperature conditions. These results are supported by observed degradation of intermediate strength proppant (ISP) recovered from an acidized well in a shallow, low-temperature formation.
Immiscible Fluid Flow Simulator
Authors: Breitenbach E.A. , Thurnau D.H. , van Poolen H.K. 
Published: December 2007

Abstract
This paper is on the MUFFS (internal program library name) computer program. It program library name) computer program. It also outlines potential applications in reservoir engineering. Actual uses range from small-scale studies of the basic fluid flow mechanics in particular circumstances to full-scale simulation particular circumstances to full-scale simulation of reservoir/aquifer systems. Potential applications in exploration, ground water, hydrology, and gas storage are also discussed.
Emphasis is placed on the versatility of MUFFS in studying a wide range of problems involving immiscible flow of one, two, or three phases in one, two, or three dimensions. Gross phases in one, two, or three dimensions. Gross effects simulation of processes is also possible. The problem solution is conducted internally in terms of a system of finite difference equations based on fundamental fluid-flow concepts and on reservoir data and well data furnished by the user. However, mathematical solution results can be viewed in engineering-oriented formats in tables and figures.
Some of the flexible input/output options of MUFFS are gained from auxiliary programs. Important among these is an economics program that may be used to analyze reservoir behavior predictions. The net result is an ability to make predictions. The net result is an ability to make combined engineering/economic forecasts of future reservoir performance.
Introduction
Petroleum reservoir engineering is a branch of applied science concerned with the quantity of fluid within rocks and the flow of such fluids through rocks. Reservoir engineering may be defined as the study of the microscopic and macroscopic behavior of multiphase fluid flow through porous systems (geometrically difficult to describe) and the application of the knowledge attained from such a study to the efficient operation of petroleum reservoirs.
With modern developments in computing numerical analysis, the practical solution of a large class of multidimensional problems has been possible, and hence the introduction of the reservoir model, mathematical model, and the petroleum or natural gas reservoir simulator. petroleum or natural gas reservoir simulator. A simulation model may be either physical or mathematical, and may represent the behavior of laboratory experiments, individual wells, or complex reservoir-aquifer systems. The simulator enables the engineer to examine and evaluate the physical and economic consequences of various alternative production policies.
Historically, the prediction of the performance of a new reservoir was based on the performance of a new reservoir was based on the knowledge of the performance of a depleted or nearly depleted reservoir with similar properties.