bluuebunny/crossref_metadata_2025_split huggingface dataset:
New Downhole Filming Amine Corrosion Inhibitor for Sweet and Sour Production
Authors: Papir Y. S. , Schroeder A. H. , Stone P. J. 
Published: December 2007

ABSTRACT
A new oil-soluble, filming amine corrosion inhibitor has been developed specifically to treat both sweet and sour corrosion in downhole applications. Its structure contains no amide groups and, thus, is more chemically and thermally stable than the amidoamine and imidazoline-based products widely used in downhole corrosion treating.
The new inhibitor has been evaluated both in the laboratory using wheel test screening methods and in the field. The field trial comprised an entire battery of 39 sour producers at the McElroy Field near Crane, Texas, and was conducted over a 14-month period. Laboratory data indicate superior film persistence of formulations of the new amine at lower concentrations, longer times, and higher temperatures than a commercial corrosion inhibitor currently in wide use throughout the Permian Basin and elsewhere. The average batterywide corrosion rate decreased from 2.5 mpy for the commercial inhibitor to 1.6 mpy for the Chevron Amine-based product. In addition, electrochemical Pair probe measurements on batch-treated wells clearly show the improved film persistence of the new material.
A New Method for Studying Phase Behavior of Enhanced Oil Recovery Surfactant Systems
Authors: Smith D. H. , Covatch G. L. 
Published: December 2007

ABSTRACT
The use of isoperibol calorimetry to obtain phase boundaries and compositions for two-phase amphiphile/water systems and three phase surfactant/oil/water/systems is demonstrated. Because the phase data are obtained without waiting for emulsions to break, the calorimetric technique is much faster than conventional methods. Furthermore, the technique yields heats of mixing (excess enthalpies), which are needed for the development of equations-of-state and the prediction of phase behavior. Because the samples studied need not transmit light, the calorimetric technique eventually may prove very useful for the study of surfactant/CO2/oil/water miscible-flood mobility control systems and systems that contain black oil.
A Practical and Comprehensive Well Logging Evaluation Technique for Modern Computers
Authors: Alcocer C. F. , Hayatdavoudi A. 
Published: December 2007

ABSTRACT
Since successful crude oil recovery is dependent on knowledge of reservoir parameters, accurate and quick evaluation of well logs is important. Consequently, a computer technique has been designed and prepared to assist engineers in well logging evaluation tasks.
The technique presented in this paper is a well Logging package written in Fortran 77 to perform well log evaluation. The overall flow of the system is: Data entry; review and editing; selection of calculations; output of results in either tabular or plotted form. The output is valuable because interpretation from either the table or the plot is faster and more accurate than interpretation from a suite of raw logs. The technique is comprehensive to perform all the fundamental typical well logging calculations. It scans several traditional combinations of well logging programs that are usually run for the evaluation of hydrocarbon wells.
This version of the package or computer system is practical to implement in a main frame computer and has been used for instructional purpose in the USL Petroleum Engineering Department.
This version is expandable by adding routines. Little, if any, rewriting will be needed. More effort is needed to produce a package which is usable without a training session. Currently a significant time, minimum 2 hours, is needed to familiarize the user with the package operation. The system is designed to perform calculation of shale volume, true formation resistivity, porosity for single and dual matrices, and fluid saturations of the flushed and virgin zones. By using a residual oil saturation and movable oil an overlay plot can be produced to visualize the average distribution of fluids and solids in the reservoir. Results yield by the package are reasonable in agreement with those results generated by commercial packages with the same objective.
CO2 Mobility Control Carbonate Precipitation: Experimental Study
Authors: Puon P. S. , Ameri S. , Aminian K. , Durham D. L. , Wasson J. A. , Watts R. J. 
Published: December 2007

ABSTRACT
One of the major problems associated with BOR in general and with CO2 flooding in particular is the tendency of the displacing fluids to bypass most of the crude oil in the flood pattern. The high mobility CO2 seeks out the path of least resistance through the largest pore openings and takes the most direct route between the injection well and the production well. Mobility control is, therefore, an important problem in CO2 flooding. Several methods have been used in an attempt to alleviate the situation, but none have been successful to a satisfactory degree. One way to overcome the tendency of CO2 to bypass the residual oil would be to plug the large pores by forming solid materials in the individual pore spaces through in situ chemical precipitation. Several relatively inexpensive salts of the alkali earth group that are soluble in water react with CO2 to form solid carbonates that can plug the pores. Once the precipitate is formed in the large pores, subsequent fluid flow will be forced to take place through alternate pore paths, thus, increasing the ultimate recovery. The overall objective of this study has been to evaluate the technical feasibility of utilizing carbonate precipitation for mobility control in CO2 flooding. The preliminary experimental work indicated that the carbonate precipitation can occur under various reservoir pressures and temperatures when the pH ranges between 7 to 8. Berea sandstone core samples have been utilized to study the effects of carbonate precipitation relative to altering/reducing permeability under a variety of pressures and temperatures. The results indicate that the permeability can be significantly reduced by in situ carbonate precipitation. In order to further investigate the nature and extent of precipitation propagation in the core samples, a number of experiments have been conducted in pairs of cores connected in parallel and series. The results indicate that the carbonate precipitation is not localized in the core samples and the permeability profile can be altered successfully. Further relative permeability experiments verify the effects of the carbonate precipitates on the flow behavior of the cores.
The Use of Convolution Type Curves for the Analysis of Drawdown and Buildup Tests
Authors: Ayestaran L. , Minhas H. N. , Kuchuk F. J. 
Published: December 2007

Abstract
One of the most important objectives of transient well-test interpretation is to recognize the well-reservoir system (identification) that is being tested, before estimating its parameters such as permeability, skin, and reservoir pressure. This paper presents a procedure for system identification and parameter estimation for single layered reservoirs using downhole pressure and flow rate measurements. However, the procedure can also be applied to commingled reservoirs if each zone is tested in accordance with the multilayer testing technique. The procedure consists of three steps. The first is a system and flow regimes identification (diagnostic) from deconvolution, and specific convolutions and their derivatives. The second step is to obtain all possible parameters and to refine the model further from flow regime analyses and type curve matching using the rate normalized pressure and its derivatives with a few selected models. Any parameter estimated from the flow regime analyses is used as initial guesses for type curve matching. The final step is the verification that allows an automatic estimation of parameters using the most probable model. At the final step, the selected model should satisfy all observed transient measurements and the past production history as well as geological and well log information.
The procedure for transient well test interpretation presented in this paper demonstrates the advantages of using downhole flow rate and pressure measurements. In addition, the paper explores the use of the Gladfelter deconvolution of pressure and flow rate data for model identification. The convolution type curves (CTC) are presented. The interpretation procedure was successfully applied to a field well test example.
Applications of the Net Present Value (NPV) in the Optimization of Hydraulic Fractures
Authors: Balen R. Mark , Meng H-Z. , Economides Michael J. 
Published: December 2007

Abstract
The concept of the net present value (NPV) has been introduced as a systematic approach in the optimization of hydraulic fractures. The scheme combines reservoir and well performance, rock mechanics principles, fracture propagation models, fracturing fluid rheology, proppant transport, and stimulation treatment variables. The method involves the graphing of a range of fracture lengths (or other treatment variables) against the NPV. The optimum length corresponds to the maximum NPV.
Two field cases (one for an oil and another for a gas well) are used for fracture treatment optimizations. Studies for each well show the impact of parameter variation, including the choice of proppant, fracturing fluid, pump rate, treatment pressure (controlled by tubular selection), and volumes of fluid and proppant injected. Variables affecting fractured well performance are also examined, e.g., tubing size and wellhead or bottomhole flowing pressure. The optimization technique also shows the cost of uncertainty and the importance to know—before the treatment—the reservoir permeability, height, and porosity. In particular, an order of magnitude variation in the permeability results in a substantial difference in the optimum fracture length (several hundred feet) and the implied maximum NPV. A study on the effect of the closure stress on proppant performance and the resulting NPV ratio also is included.
This systematic approach to hydraulic fracture design is an important tool in the identification of the crucial parameters affecting a particular job, and allows their control before and during the treatment.
Effects of Stimulation/Completion Practices on Eastern Devonian Shale Well Productivity
Authors: Nearing T. R. , Startzman R. A. 
Published: December 2007

ABSTRACT
A variety of completion and stimulation practices have been used in Eastern Devonian Shale wells during the more than 60 years since its initial development. Over 1000 wells in thirty-four counties located in the west central part of the Appalachian basin, were analyzed to investigate the effects of these practices on well productivity. This study represents the largest investigation to date of post-treatment response using a reliable indicator of the well's long-term deliverability for comparing both explosive and hydraulic fracturing methods.
The traditional measure of well productivity, initial open flow, gives a poor indication of the well's long-term potential. The cause of this poor relationship can be partially attributed to the insufficient test times run during open flow measurements. A more representative indicator of long-term potential, available early in the well's life, has been identified.
Based on location data from wells in the study area, field development of the Devonian shale has been associated with existing localized fold/fault systems. Drilling activity appears to concentrate around structures created as a result of major basement tectonic activity.
The purpose of this study was to isolate the effects of stimulation practices from the background effects of geology and differential reservoir depletion rates. By recognizing these sources of variability, comparison of well productivity for the various stimulation practices was made using standard statistical inference techniques.
The results of this study indicate that larger stimulation treatments, either by explosive shooting or hydraulic fracturing, have not generated incremental improvements in well productivity on a regular basis. A group of post-1975 wells were analyzed to limit the time dependant effects of reservoir depletion. Results from this group indicated natural completions, at a statistically significant level, exhibited greater productivity as compared to that of nitrogen fractured or shot wells. In evaluating the more modern practice of hydraulic fracturing, the foam fractured wells exhibited significantly greater productivity than comparable wells stimulated by explosive shooting.
Field Measurements of Dynamic Pressure and Seismic Activity During Foam Fracturing
Authors: Locke C. D. , Overbey W. K. , Yost A. B. 
Published: December 2007

ABSTRACT
Results of a highly-instrumented multiple-well field test to measure pressure responses during hydraulic stimulation of a naturally-fractured gas reservoir are presented. The field test consisted of a 70,000 gallon (265 m3) "foam frac" in one of four test wells while monitoring bottomhole pressures in each of the four wells and monitoring the site with an array of tiltmeters. A 75-quality sand-laden foam was injected into the naturally fractured formation at a rate of 20 bbl/min (3.2 m3/min). The injection rate was held nearly constant except for two brief interruptions. Sand concentration during the treatment ranged from zero to two and one-half pounds per gallon while average one pound per gallon. Bottomhole pressures were monitored in the fraced well and in three observation wells. Tiltmeters were installed at 12 surface locations encircling the stimulated well at distances of approximately 600 to 1000 feet (180 to 300 meters) to aid in determining the geometry of the induced fracture.
The tiltmeter and pressure responses were analyzed in conjunction with pre- and post-stimulation interference tests to obtain fracture geometry. Eight of the twelve tiltmeters gave clear and analyzable responses. Application of computer codes to the field data provided estimates of fracture geometry caused by the treatment. Bottomhole pressure responses at the three offset wells ranged from 15 to 40 psi (100 to 275 kPa), and occurred gradually over a period of several hours with occasional rapid increases to 1 to 2 psi (7 to 14 kPa) within a 15-second interval.
Centrifuge Measurements of Capillary Pressure: Part 2 – Cavitation
Authors: Hirasaki G. J. , O'Meara D. J. , Rohan J. A. 
Published: December 2007

ABSTRACT
Centrifuge air/water capillary pressure measurements made at one atmosphere ambient pressure can have the liquid in tension (negative absolute pressure) and cavitation of the liquid is suspect. Theoretical arguments show that cavitation in the liquid saturated region should not occur with water-wet rocks having capillary entry pressure less than three atmospheres. Thermodynamics argue that water that is in hydrostatic equilibrium in the pore space that has been invaded by a gas that is also in hydrostatic equilibrium can be in chemical equilibrium with the water vapor in the gas. An experiment showed no evidence of cavitation in rocks with a capillary entry pressure of 50 psi.
Case History: The Design and Construction of Earthquake-Resistant Platform Drilling Rigs
Authors: Cardenas J. L. , Fetterly W. D. , Fowler J. R. 
Published: December 2007

ABSTRACT
Offshore platform rigs that can survive a potential earthquake are currently being designed and built by utilizing computer analysis. The rigs are modeled using finite element analysis and analyzed using the dynamic response spectrum method. By following this approach the rigs can be operated safely in earthquakeprone areas such as California and Alaska.
Oil Muds in Large-Diameter, Highly Deviated Wells: Solving the Cuttings Removal Problem
Authors: Seeberger M. H. , Matlock R. W. , Hanson P. M. 
Published: December 2007

ABSTRACT
An investigation of hole cleaning in large diameter, high angle holes by oil-base muds is summarized. The rheological requirements which must be met to achieve efficient cuttings removal will be discussed. Laboratory and field results using an additive which helps oil-base muds meet these requirements are described.
Forecast and Review: Offshore Rig Activity
Authors: Lawrence S. D. , Gabrielsen G. 
Published: December 2007

ABSTRACT
Forecasting market trends or developments, with a reasonable degree of accuracy, has never been easy. The billions of dollars in offshore drilling assets and/or debt that have been written down are a testament to the difficulty in developing an accurate forecast.
Forecasts are difficult because the individual(s) preparing a forecast must: (1) assemble and analyze data, (2) determine what data is relevant, (3) identify trends or market developments, and, (4) develop an understanding of the often complex interrelationships normally found in an industry. All this to be done before developing at a forecast.
In this paper, an Econometric Model, developed during the past eight years, will be reviewed.
The Model is primarily based on: (1) explicit quantitative descriptions of how the offshore rig market has performed since 1972, and (2) energy prices. In this paper, key factors which influence offshore rig demand, supply, active utilization and dayrates will be reviewed. And, specific Projections for 1989 will be presented, with accompanying graphs, based on the Econometric Model and potential values, or outcomes, for the industry's key factors
Drilling Decisions in Periods of Oil and Gas Price Volatility
Authors: Kerridge I. C. 
Published: December 2007

ABSTRACT
Most drilling decisions, after weighing the geological prospects, are made with the help of a rate of return on investment calculation. Critical to the results are oil and/or gas price assumptions, although they are of diminishing importance over the period covered in the calculation.
Price volatility in the recent past not only makes price assumptions more difficult, it can prompt inaction on prospects offering an adequate return. While not suggesting that oil or gas prices can be predicted or that traditional analysis should be abandoned, this paper suggests some factors (often non-quantifiable) that should be considered in making the decision whether or not to drill.
Some of these factors include: Finding cost differentials.Political risk."Sunk costs."Reserves trend of firm or producer.Auto correlation of future prices and costs.Firm or producer's exploration strategy.National welfare and security.True cost of purchased reserves.Contractual requirements.
Statistics and comments on trends relative to the above factors are presented where available. (e.g., the degree of correlation between the composite price of oil and gas and drilling costs per foot.)
The conclusion of the paper is that the drilling decision can be made sounder by formalized consideration of a number of economic or quasi-economic factors which lie beyond the realm of quantifiable rate of return projections.
Preventive Maintenance and the Drilling Contractor
Authors: Shepard J. S. 
Published: December 2007

ABSTRACT
No matter what state the drilling industry is in, significant cost savings, and higher profit margins are limited to only a few areas within control of the management of a drilling contractor.
The primary area of cost control is labor, both in terms of rig manning levels and office overhead. Most all drilling contractors still in business today have experienced the harsh reality of cost reduction in this area. However, the rig must still operate, and do so with far greater efficiency than ever before.In terms of dollars, the only major area remaining to substantially reduce costs is in repair and maintenance. Although this can be handled in many different ways, one of the best methods is by having a well designed and implemented Preventie Maintenance (P.M.) System. Such a system can be defined as "a means by which repair and maintenance costs can be controlled both at the rig level, and by upper management, with information needed to make decisions."
For offshore rigs, the number of pieces of equipment that require maintenance can reach upwards to 600 in number. This can translate into thousands of machines for companies with multiple rig fleets. Further, each machine, requires different maintenance at varying frequencies, different skill levels, and is subject to different regulatory requirements, and environmental conditions. For this reason, computerized systems are necessary in order to minimize the overhead burden of administering the system, and to provide fast analytical capability.
Monitoring Engine Oil
Authors: Fullerton R. D. 
Published: December 2007

ABSTRACT
Reduced operating costs and improved engine maintenance can be accomplished through scheduled monitoring of oil samples. Helmerich & Payne International Drilling Co. utilizes an oil sampling service as one method to reduce operating costs and to establish parameters for monitoring the condition of engines.
The purpose of this paper is to discuss the cost effectiveness of implementing an oil sampling service, adherence to sample test results, and the development of parameters by which to efficiently operate the engines. Helmerich & Payne International Drilling Co. uses Caterpillar model D379, D398, and D399 diesel engines as the rigs' primary power source. Over the past four years, the use of an oil sampling service has increased the tiro between oil changes from the recommended 500 service hours to over 1000 service hours. Field data confirms that these extended intervals have translated directly into savings of $200,000.00 in the first three years of the program. As a result, H&P has established new guidelines for engine maintenance. The use of an oil sampling service has allowed H&P to reduce engine operating costs while maintaining its standard of optimum engine performance.
Batchset Optimization on Jolliet Project
Authors: Watkins S. S. , Beato C. L. 
Published: December 2007

ABSTRACT
Conoco's Jolliet Project is a deepwater Tension Leg Well Platform (TLWP) development project in 1758 feet [536m] of water in the Gulf of Mexico. Sixteen 30" [762mm] and 20" [508mm] casing strings were batchset following installation of the drilling template in July, 1987. Batchsetting was expected to reduce the project costs through operational optimization and by decreasing the number of blowout preventer (BOP) stack trips during the drilling phase. The batchsetting operation was completed in 36 days, an average of 2.25 days per well.
This paper discusses the time and cost saved during batchsetting and how the savings were realized through planning and execution. During preplanning, 15 days were saved by improving equipment and procedures and initiating the use of unconventional technology. During the execution, 29 days were saved through use of simultaneous operations, successful troubleshooting of prototype equipment, coordination of logistics, and the use of a rigsite critique system. During the drilling phase, BOP stack trip reduction savings have been estimated at 29 days. Total savings for batchsetting have been estimated at 73 days and $6.6 million.
Planning and execution were improved by the interaction of engineering and operations personnel. This teamwork was the driving force behind the success of batchsetting on Jolliet and directly contributed to optimization savings. It was possible due to management's approach of committing all personnel early in the project. These principles and methodology are not unique, but they have rarely been implemented with this degree of success.