bluuebunny/crossref_metadata_2025 huggingface dataset:
The Design and Testing of Subsea Production Equipment: Current Practice and Potential for the Future
Authors: Cort A. J. C. , Ford J. T.
Published: December 2007

This paper presents an analysis of the current approach to the design and testing of equipment used in subsea developments. The paper critically assesses the current equipment specification, design, manufacture and testing process. An essential part of the analysis is a review of the standards used by the industry and statutory regulations which impact on this process.

It raises significant questions about the efficacy of the design and testing procedures and the role of the regulating bodies in that process. It discusses the impact of poor specification and design procedures, and inadequate testing, of the safety and reliability of the equipment. As a consequence of the analysis it is suggested that the manner in which equipment is specified, designed and tested may need to be changed in order to meet future needs.

The above issues are focused, by considering the production of a subsea wellhead, from specification by the operator to delivery by the manufacturer.
Incident Investigations - A Total Quality Management (TQM) Method
Authors: Fitts Travis G.
Published: December 2007

The typical incident investigation does not produce optimal results. Investigations have historically created barriers for safety improvement and exposed companies to unnecessary financial liability. The objective of this poster session is to introduce a process that will: Improve the reliability of reporting, tracking, and statistical analysis.Increase the effectiveness of corrective actions.Strengthen an organization’s ability to defend itself should litigation arise.
Remediation of Normally Occurring Radioactive Material (N.O.R.M.): A Field Trial
Authors: Orum J. D. , Baudoin D. , Briscoe O.
Published: December 2007

This paper describes a case history where 200 barrels of NORM contaminated sands and sludges were remediated to below regulatory limits and subsequently disposed as Non-hazardous Oilfield Waste (NOW.). The material treated initially registered as high as 180 pCi/gram of Radium 226. Upon completion of the remediation process, all materials were reduced to below 30 pCi/gram with some samples registering as low as 3 pCi/gram (background). The lower levels of radiation registered were a direct result of treating time. As a result of this process, no by-products were generated which fall under NORM regulated levels. The resulting data from this remediation of NORM waste were scrutinized by applicable regulatory agencies and found to be an acceptable method of remediation.
Oil and Grease Discharge Regulations in the United States and Equipment Capabilities
Authors: Otto G. H. , Arnold K. E.
Published: December 2007

This paper traces the history of Gulf of Mexico statistical studies of oil and grease removal capability for produced water treating system from the 1974 Brown and Root study through the 1993 survey of 292 platforms. The changing EPA policy of regulation based upon process capability to one of selective analysis and policy driven regulations is explained. Over 3,000 observations from the 1993 study were used to analyze the ability of existing systems to meet the 42/29 mg/1 discharge limits promulgated in 1994. In addition, the data was reviewed to see if conclusions could be reached on actual field performance of the full range of water treating equipment and system configurations including skimmers, hydraulic flotation units, mechanical flotation units, hydrocyclones and filters.
Successful History Matching of Chaunoy Field Reservoir Behavior Using Geostatistical Modeling
Authors: Lemouzy P. M. , Parpant J. , Eschard R. , Bacchiana C. , Morelon I. , Smart B.
Published: December 2007

An integrated study combining sedimentological and sequence stratigraphy analysis, geostatistical simulations and validation by production history simulation has been performed in the Chaunoy field reservoir. The reservoir is a part of a distal alluvial fan system, in the Keuper series of the Paris Basin (France). RFT surveys suggest a layered behavior. Nevertheless, the low extension of reservoir bodies (small ribbon channels interbedded with flood-plain and lacustrine mudstones) made it difficult to set ut a satisfactory correlation scheme in the past studies, resulting in difficulties in matching the production history.

Core and log analysis yielded the conceptual geological model. Geostatistical analysis enabled to its validation and quantification. Inside each genetic unit, repartition of lithotypes and of petrophysical properties were modelled by geostatistical simulations. As the horizontal variogram ranges proved to be below the average well spacing, three high resolution models were built, with different horizontal variogram ranges, all smaller than well-spacing (1/8, 1/2 or 1 times the well spacing). After scaling-up of the resulting petrophysical models, simulations of the ten-year production history were performed in each model. By comparing the simulated production data with the field production history, the characterization study was validated. A satisfactory match was obtained on the main zone of the reservoir, validating the correlation scheme and explaining the observed layered behavior.
Application of Well Production Data to Reservoir Characterization
Authors: Yang Huade , Gao Yaming , Yang An-Ping
Published: December 2007

Many researchers have attempted to characterize reservoirs by qualitatively integrating all available seismic, geological, well logging, and core data. However, very few efforts have been made to incorporate the production data, an important reflection of reservoir properties, in reservoir characterization researches. One of the main reasons for the lack of efforts can be attributed to difficulties in determining reservoir properties from well performance data. In our study, well production data are used to derive relative trends of reservoir property distributions instead of calculating the exact reservoir parameters. These trends can be used as soft data in integrated reservoir characterization studies. Our approach was to partition reservoir into separate drainage area for each well and derive average reservoir pressure within this drainage area of a well from production data. The productivity index was then calculated and mapped using geostatistical techniques. Reservoir permeability trends were then derived from this field productivity index mapping. The validity of our approach was then checked using a conventional reservoir simulator.
Development of An Electronic Information System for the Petroleum Industry
Authors: Martin F. David
Published: December 2007

This paper discusses the development of the Gas and Oil Technology Exchange and Communication Highway (GO-TECH). GO-TECH is a PC-based networking system designed to make high-speed electronic links readily accessible to the petroleum community for rapidly exchanging information, data, ideas, and technology. Experience gained during the first year of operation is discussed, and the evolution of GO-TECH shows how a regional producer advisory group guided the development of the system. A brief background of the Internet and World Wide Web will be provided, and a glossary of related technical terms is provided for those not familiar with the terminology in this area.
Coupled Fluid Flow and Geomechanics in Reservoir Study -I. Theory and Governing Equations
Authors: Chen H. -Y. , Teufel L. W. , Lee R. L.
Published: December 2007

The purpose of this study is to examine Biot’s two-phase (fluid and rock), isothermal, linear poroelastic theory from the conventional porous fluid-flow modeling point of view. Biot’s theory and the published applications are oriented more toward rock mechanics than fluid flow. Our goal is to preserve the commonly used systematic porous fluid-flow modeling and include geomechanics as an additional module. By developing such an approach, complex reservoir situations involving geomechanical issues (e.g., naturally fractured reservoirs, stress-sensitive reservoirs) can be pursued more systematically and easily. We show how the conventional fluid-flow formulations is extended to a coupled fluid-flow-geomechanics model. Consistent interpretation of various rock compressibilities and the effective stress law are shown to be critical in achieving the coupling. The "total (or system) compressibility" commonly used in reservoir engineering is shown to be a function of boundary conditions. Under the simplest case (isotropic homogeneous material properties), the fluid pressure satisfies a fourth-order equation instead of the conventional second-order diffusion equation. Limiting cases include nondeformable, incompressible fluid and solid, and constant mean normal stress are analyzed.
Development and Exploitation Strategies in a High Pressure-Temperature Reservoir With a Complex Hydrocarbon Fluid Column.
Authors: Maan N. , Rosales E. , Medina H.
Published: December 2007

This paper summarizes an interdisciplinary study performed to plan final Reservoir Development and Secondary Recovery Strategies for The Carito Field discovered in late 1987.

Carito is a very large oil Field located in Northeastern Venezuela, with an estimated Volumetric Oil in Place of 1.8 Billion Stb. Production is mainly from Naricual Formation with a thickness of about 1300 feet in a faulted anticline. At the time of this Study, 25 wells had been drilled below 12200 ft ss. These wells were producing about 90000 Stb/D through 39 completions. Original reservoir pressure was abnormally high (11300 psig at 14040 ft SS) and the Temperature averages 300 degrees Fahrenheit. The field shows a graded fluid system that varies from a gas condensate to a medium oil. Gas cap to oil zone ratio is about 1.2 and crude oil gravity varies with depth from 36 to 21 API degrees.

The simulation study, conducted to establish the optimum exploitation strategy, incorporated a detailed geologic model based on seismic, sedimentary environment, and production geologic concepts. The data from the geologic model, routine and special test data from conventional cores, and the data from 58 fluid analysis were consolidated in a numerical reservoir simulator model, which predicted the potential reservoir performance under various Development, Production and Secondary Recovery Planning.

The results of this study led us to design a Gas Injection Secondary Recovery Process encompassing a rate injection of 600 MMScf/D through 10 injector wells and the perforation of an additional 16 producer wells. We expect to double the natural depletion oil Recovery as a consequence of the Pressure Maintenance Program.
New Data Reduction Developments for Relative Permeability Determination
Authors: Kalbus James S. , Christiansen Richard L.
Published: December 2007

Modifications of analytical methods were developed for obtaining relative permeability relationships from displacement experiments conducted in a centrifuge or at normal gravity conditions. The methods are modifications of the Johnson-Bossler-Naumann method (for normal gravity experiments) and the Hagoort method (for centrifuge experiments). As demonstrated by application to numerically simulated experiments, the methods accurately correct for capillary end effects.
State-Of-The-Art in Permeability Determination From Well Log Data: Part 2-Verifiable, Accurate Permeability Predictions, the Touch-Stone of All Models
Authors: Mohaghegh S. , Balan B. , Ameri S.
Published: December 2007

The ultimate test for any technique that bears the claim of permeability prediction from well log data, is accurate and verifiable prediction of permeability for wells from which only the well log data is available. So far all the available models and techniques have been tried on data that includes both well logs and the corresponding permeability values. This approach at best is nothing more than linear or nonlinear curve fitting. The objective of this paper is to test the capability of the most promising of these techniques in independent (where corresponding permeability values are not available or have not been used in development of the model) prediction of permeability in a heterogeneous formation.

Since the empirical approaches for permeability prediction are mostly directed toward developing mathematical models from given data in particular formations, it has been shown that they lack the required generalization capability for the purposes of this study. These approaches have concentrated on modeling formation permeability as a function of porosity and irreducible water saturation. These models will be briefly discussed. The main focus of this paper will be on two techniques that show potentials in achieving the goal that was mentioned above. These techniques are "Multiple Regression" and "Virtual Measurements using Artificial Neural Networks." For the purposes of this study several wells from a heterogeneous formation in West Virginia were selected. Well log data and corresponding permeability values for these wells were available. In separate tests all data from an entire well were designated and put aside.

The techniques were applied to the remaining data and a permeability model for the field was developed. The model was then applied to the well that was separated from the rest of the data earlier and the results were compared. This approach will test the generalization power of each technique. After all, this is the way that these techniques are used in the real life situations.

The result will show that although Multiple Regression provides acceptable results for wells that were used during model development, (good curve fitting,) it lacks a consistent generalization capability, meaning that it does not perform as well with data it has not been exposed to (the data from well that has been put aside). On the other hand, Virtual Measurement technique provides a steady generalization power. This technique is able to perform the permeability prediction task even for the entire wells with no prior exposure to their permeability profile.
Helical Flow of Bentonite Slurries
Authors: Walker Richard E. , Al-Rawi Othmen
Published: December 2007

Laboratory flow experiments with four bentonite-water mixtures verified a method of calculation for laminar helical flow. The calculation technique includes the influence of rotating drill pipe and can give velocity and viscosity profiles as well as flowing pressure drop, thus it can be used to evaluate pressure drop, thus it can be used to evaluate muds under various operating conditions for hole cleaning and equivalent circulating density. The method proposed by Coleman and Noll uses a viscosity based on the vector value of the angular and axial stress components and a viscosity-stress relation measured with conventional rheometers.

One explanation of "gelling" in washed-out areas of a wellbore is suggested by the rheological behavior of two bentonite-water mixtures used in the experiments. The shear stress of these liquids increased at very low shear rates so two shear rates could exist for some values of shear stress. Tests in a rotating rheometer showed that some bentonite-water mixtures give, for the same shear stress, much lower shear rates when measured under constant stress conditions than under constant rate conditions. This behavior was limited to a stress range and did not occur above critical stress.

Introduction

The objective of this work is to experimentally test the validity (using a bentonite water fluid) of a method of predicting laminar helical flow proposed by Coleman and Noll and also by Fredrickson. The method of calculation has been shown experimentally to be correct for a polymer liquid in helical flow (Refs. 3 and 4) and was used by Savins and Wallick to predict velocity profiles and pressure drops in the annulus of a drilling well assuming that the liquid followed a three-constant Oldroyd liquid model. These calculations showed that rotating drill pipe can have a marked influence on the velocity profile and the flowing pressure drop. No experimental justification of the calculation methods has been done with bentonite or other clay materials.

If the calculation method is valid for drilling muds considerable additional information can be obtained about the fluid characteristics in the annulus. This will allow better predictions of the ability of liquid to carry cuttings to the surface, the equivalent circulating density, and rheological test conditions for evaluation of mud properties. For example, an indication of the ability of a liquid to carry cuttings might be inferred from the viscosity at various radial points in the annulus as well as the axial velocity profile.
The Use of Inertial Force and Low Shear Viscosity to Predict Cleanup of Fracturing Fluids within Proppant Packs
Authors: Penny Glenn S. , Jin Liang
Published: December 2007

This paper describes the development and use of laboratory data to show the impact of multiphase, non-Darcy flow and gel damage upon gas production from hydraulic fractures. In the work, the percent cleanup is related to the molecular weight and concentration of the gel remaining in the proppant pack and the inertial force available from the flow of gas and liquids during cleanup and production. The impact of proppant permeability and multiphase, non-Darcy flow is further combined with inertial force and gel damage to provide a newly developed relationship to predict the degree of cleanup. The new relationship can be used to calculate the effective conductivity for various proppant types, sizes and concentrations vs. closure, temperature, gel and breaker concentration, and prevailing gas/water/oil ratios. The calculated effective conductivities can then be used to predict gas productivity and economics under various conditions of multiphase, non-Darcy flow.

The results of the testing show that multiphase, non-Darcy flow dramatically increases the difference between the effective conductivities of various proppants and fracturing fluids with different retained permeabilities. The laboratory data and field observations show that when multiphase flow is taken into account, fracturing fluids with high retained permeabilities and premium high conductivity proppants can produce at as much as twice the gas production rate of fluids with 50% cleanup in gas wells producing as little as 10 barrels of water or condensate per MMCF. Using the developed criteria, proppants and fluids can be selected to optimize gas production from wells based upon prevailing reservoir conditions.
Prediction of Formation Damage During Fluid Injection into Fractured, Low Permeability Reservoirs via Neural Networks
Authors: Nikravesh M. , Kovscek A. R. , Johnston R. M. , Patzek T. W.
Published: December 2007

The coupled, nonlinear and dynamic mechanisms that affect fluid injection for pressure maintenance or displacement, and oil production, are not well understood in low permeability fractured reservoirs. Thus, it is difficult to select an injection policy which maximizes oil recovery while minimizing formation damage caused by fluid injection and withdrawal. Here, we show that neural network models can be developed and used to predict, on a well-by-well basis, the dynamics of low permeability, fractured reservoirs undergoing fluid injection. The networks are trained using historical data from field operations.

We present an example from (i) a water and (ii) a steam injection project where over-pressurization has lead to unwanted extensions of fractures. First, using data from a waterflood project in the South Belridge Diatomite (Kern County, CA), we have built a neural network to predict wellhead pressure as a function of injection rate, and vice versa. The resulting model provides an excellent correlation between the inputs and outputs and recognizes major patterns in the input data structure, even though the behavior of the waterflood is complex. Second, using data from a dual injector steam drive pilot in the same field, we have created neural networks which correlate the injection pressures and rates, and temperature responses in seven observation wells. Assuming a future injection pressure policy, the neural networks predict the injection rate and growth of heated reservoir volume. These predictions are then combined with a history-matching reservoir simulator to demonstrate how predictive simulation can be achieved even when mechanisms of steam injection and oil displacement into a tight fractured rock are not fully understood.
Water Quality for Water Injection Wells
Authors: Rochon J. , Creusot M. R. , Rivet P. , Roque C. , Renard M.
Published: December 2007

A multidisciplinary study has been carried out so as to characterize the permeability impairment due to suspended particles during water injection. The approach is based on extensive laboratory experiments reproducing the complete range of parameters met in the industry. Experiments were carried out at both constant flowrate and constant pressure gradient. They reproduce static filtration conditions, i.e. without a flow component tangential to the rock face such as can occur when there are open fractures.

The analysis of experimental results has confirmed that injectivity damage can be separated into two successive processes. Internal permeability damage close to the entry face switches to the build-up of an external filter cake after the injection of a critical volume. This is true even when particles are very small as compared to the size of the pore throats. Analytical equations have been developped for each mechanism, as well as for the critical cumulative injection when the external cake starts to form. These equations require at most two parameters. The extensive range of experimental conditions in our laboratory study enables us to propose correlations for the values of these parameters from basic data (velocity, concentration, particle size).
Ultrasonic Removal of Organic Deposits and Polymer Induced Formation Damage
Authors: Roberts Peter M. , Venkitaraman Adinathan , Sharma Mukul M.
Published: December 2007

Experiments were conducted that evaluate the feasibility of using high intensity acoustic sources to remove near wellbore formation damage caused by organic deposits (paraffins and asphaltenes) and polymers (HEC). It is shown that mechanical agitation provided by the acoustic waves effectively re-suspends the paraffin and restores the effective permeability of the core to oil to its undamaged condition in a relatively short period of time. The depth of treatment is approximately 12-15 cm. This suggests that an acoustic source with or without solvents may provide an effective method of removing paraffins from the wellbore and the near wellbore region.

Acoustics was not found to be as effective at restoring the permeability of cores damaged by polymers (HEC). Only small (factor of 1.5) increases in permeability were obtained for both poorly mixed and well mixed HEC.

Experiments conducted over a range of frequencies and acoustic intensities allow us to specify the design requirements for a field deployable transducer. Eight such transducers have been incorporated into a through tubing tool that has recently been built and is now available for field testing.

Our results demonstrate that acoustic cleaning may be a viable method for cleaning both the wellbore and near wellbore region when paraffin precipitation is a problem. The method would be particularly effective at treating long sections of pay (horizontal wells) where chemical methods may be too expensive. Acoustic cleaning is much less effective for treating polymer damage problems.
Prospects For Nuclear Energy
Authors: Simpson John W.
Published: December 2007

1970 Annual Fall Meeting, October 4–7, 1970 - Houston, TX

I appreciate very much the invitation to address this meeting today and to talk about nuclear power.

I would like to make a few points about nuclear power — such as why we must move ahead with the power — such as why we must move ahead with the development of this energy source — and then discuss my subject in terms of kilowatts and dollars and cents.

There are several very compelling reasons why the continued development of nuclear power is of the greatest importance to this nation.

The first and most obvious reason is that our utilities urgently need additional capacity on their systems. Our electrical energy crisis was dramatically brought home to millions of people this year on the last day of summer when the entire east coast found itself in the throes of a massive brownout stretching from New England to South Carolina over to Ohio.
Gas Availability from Casinghead Systems
Authors: Rist Barry C.
Published: December 2007

The Hugoton Anadarko Area has seen the growth of several large casinghead systems during the past few years. Since pipe line companies historically look for the long term sources of supply, analyses of various casinghead gas gathering systems have been made. Gas supply from these systems can most generally be depended upon for long periods of time. The system should be located in a developing gas and oil area and should be available early in the development life.

The casinghead reserves per well can be expected to be small and, in order to maintain a break-even position, 20 - 25% new wells must be connected each year. In the successful operation of a casinghead system, the company must be aggressive. The drilling slump has not appreciably effected those systems whose managements are active.

The Hugoton Anadarko Area has 2.5 Tcf of proved remaining recoverable casinghead gas reserves at January 1, 1970.

Introduction

The Hugoton Anadarko Area is located on the map shown on Page 5. The proved remaining recoverable natural gas reserves for the total Hugoton Anadarko Area has been steadily declining since 1959 at an average rate of 1.25 Tcf/year, see Fig. 14. However, during this time the casinghead gas reserves continued to increase, peaking in 1965 at a remaining recoverable reserve of 3.6 Tcf of gas. When this trend was noticed in the early 1960's, an evaluation was set in motion to determine some of the more desirable characteristics of a casinghead gas gathering system and if they could be depended upon for long term supplies of gas.

In analyzing this question, two large problems are encountered immediately. The problems are encountered immediately. The first problem is that all of the casinghead systems are very complex. The second problem encountered is that very little problem encountered is that very little information concerning these systems is available for analysis.
Anadarko Basin, Buffalo Wallow Field - Operation of Deep Gas Wells and Gathering System Serving Them
Authors: Richards J.D. , Swanson Thomas C.
Published: December 2007

The Buffalo wallow (Hunton 19,600 ft.) field was discovered November 25, 1967, and during the ensuing period to the present, very significant technology in the areas of drilling, completion, producing, and pipelining has been developed. The problems encountered have been many but, as is the case in any new field development, application of the correct technology will evidence itself in the success achieve. Through diligent efforts to achieve cooperation between operator and purchaser, the task of completing, equipping, and commencement of sales from these wells was minimized. Subsequent operating problems have been more easily solved through this cooperative effort.

Introduction

The Buffalo Wallow (Hunton 19,600 ft.) field was discovered on November 25, 1967, by the Union Oil Company of Calif. No. 1 Bradstreet in which Gulf has a 25 percent working interest. There are presently 12 completed wells in the field with development still in progress in the south portion of the field. The Buffalo Wallow (Morrow) field was discovered on June 10, 1969, by the Jake L. Hamon No. 1 Mack. Completions to date number 8 and there is still considerable infill drilling to be done as well as potentially extending the field boundaries. Fig. potentially extending the field boundaries. Fig. No. 1 depicts the field in its stage of development on September 15, 1970.

There are currently three purchasers in the field with sales to Natural Gas Pipeline Co. of America commencing on February 6, 1969, to Kansas-Nebraska Gas Co. on November 14, 1969, and to Pioneer Natural Gas CO. on August 5, 1970. Cumulative volumes run from Buffalo Wallow through August, 1970, approximate 60,000 MMcf.

Kansas-Nebraska takes all of Gulf's working interest gas from the field as well as considerable volumes from others. Gulf has completed 6 Hunton wells and two Morrow wells to date and have, through the efforts of many people, achieved this very successfully. My people, achieved this very successfully. My portion of this paper will deal with the portion of this paper will deal with the experience gained in completion, equipment installation, and subsequent producing stages of this development.
A Statistical Method for Judging the Adequacy of a Numerical Reservoir Simulation
Authors: Slater George E. , Durrer Erwin J.
Published: December 2007

The confidence that one places in predictions made by a numerical reservoir predictions made by a numerical reservoir simulation study can only be qualitatively expressed at present. The criterion generally used for judging the adequacy of these predictions is the "goodness" or the "badness" of a performance history match over a period of time. If a "good match" is obtained, then rules of thumb say that the predictions may be valid for a like period of time. Many rules of thumb exist, but most are quite similar. This paper outlines a method and gives criteria for quantitatively judging the adequacy not only of the predictions, but also of the performance match period.

Generally, simulation models are based on the finite difference solution of a partial differential equation describing flow through porous media. The authors show that this equation can be expressed in the form of a linear algebraic equation whose coefficients correspond to the transmissibility and storage terms of the finite difference equation. The variates correspond to combinations of pressures in adjoining grid blocks and to injection and production rates. Thereby, reservoir history matching is analogous to an estimation of these coefficients.

Statistics measuring the adequacy of the estimation by regression, methods might then be extended to numerical simulation models. In particular, the multiple correlation coefficient and particular, the multiple correlation coefficient and the observed F-ratio (regression mean square/ residual mean square) are the criteria for judging the goodness of the ensuing prediction in regression analysis.

The adaptation of the multiple correlation coefficient to reservoir simulation models is discussed. There is no straightforward adaptation of the F-ratio, but a relationship similar to the F-ratio may provide a useful indication of the goodness of the prediction, likewise, the concept of the standard error and confidence intervals may prove valuable in estimating the quality of a numerical simulation.
An Acid-Solvent Stimulation Technique for Low Gravity Crudes
Authors: Minter Rick B. , Davis Edward E. , Conway Bruce E.
Published: December 2007

The technique of acid-solvent stimulation utilizes a combination of processes which are designed to restore productivity to wells producing low gravity crude from fractured shale producing low gravity crude from fractured shale reservoirs. Productive intervals, ranging from 300 ft. to 1500 ft. have been successfully treated. Solvent is circulated down the casing-tubing annulus to remove asphaltines and expose calcium carbonate scale deposited on the slotted liners and the formation. Liners are then washed with water to remove a maximum amount of scale. The well is stimulated with HCI and HF acid utilizing Unibeads, a wax based plugging agent, to divert the acid in order to more uniformly stimulate the interval.

The fractured shale in the Cat Can on Field south of Santa Maria, California, highly permeable reservoir which produces low gravity crude and is in an advanced stage of depletion. Early well stimulations were accomplished with 3000 to 5000 gal. of 15% HCl acid. Washing of the perforations and staging of larger acid volumes were introduced to increase the effectiveness of the treatments. The diverting character of Unibeads was proven to be effective by pressure versus injection time plots taken during the stimulation of several wells. Later a solvent prewash was added. Although the treatment prewash was added. Although the treatment has become more involved and some problems have been encountered in circulating the solvent, evidence indicates that the Later treatments are more effective.

The production histories of selected wells have been chosen to illustrate and compare stimulation response. Twenty-one wells from two separate reservoirs have been stimulated utilizing the acid-solvent treatment. Increases in producing rates have varied from 25 to over 200 BCPD.
Clean-Up at Santa Barbara
Authors: Stracke K.J.
Published: December 2007

A leak in the Santa Barbara Channel 5-1/2 miles offshore resulted in oil contamination along nearly 80 miles of California shoreline. The initial efforts to disperse the oil slick and methods used to restore the beaches, harbors, and seawalls are discussed. Aspects of various other facets of the cleanup operations are also presented.

By June 1, 1969, four months after the leak occurred, the beaches were available for general use except for occasional recontamination. This is evidence of the effectiveness of the methods.

Introduction

The Santa Barbara Channel, which lies off the central coast of California, extends from Point Conception to an area beyond the City of Ventura - a distance of nearly 80 miles. The channel is oriented in a general east to Nest direction with the mainland on the north and four channel islands on the south.

In February 1968, the first major federal lease sale off California was held. Union, Gulf, Mobil, and Texaco were the successful bidders on Parcel 402 located approximately 5-1/2 miles offshore near the city of Santa Barbara. Union subsequently became the operator for the group. On January 28, 1969, during routine drilling operations, gas, and later oil, unexpectedly began to flow to the surface from the fifth well drilled from Platform A. Although blowout preventers closed Platform A. Although blowout preventers closed to shut in the well, gas and oil continued to flow into the Santa Barbara Channel through fissures in the ocean floor. Within 24 hours, an oil slick of approximately 25 square miles extended easterly from the platform. Patches of oil were breaking off from the main body in wind rows. These patches were trending toward the Santa Barbara, Montecito, Summerland, and Carpinteria beaches.
The Role Of Unit Or Operating Agreements And Selection Of Participation Factors In Secondary Recovery
Authors: Khan Anwar A. , Power Harry H.
Published: December 2007

Unit operation has lead to sound practices in the conservation of oil and gas for at least the past thirty years. The early endeavors of Earl Oliver, who served as Chairman of the Stabilization Committee of the Petroleum Division, A.I.M.M.E., Henry L. Doherty, former President of Cities Service Company and recipient of the Anthony F. Lucas Award, Joseph E. Pogue of Chase National Bank, General Ernest O. Thompson of the Texas Railroad Commission, Robert E. Hardwicke of Fort Worth, and many other far-sighted oil men, including commissioners, geologists, land-men, engineers, lawyers, and accountants, are legion. Numerous examples of cooperative unit agreements in Texas and elsewhere not only show increasing reliance on these activities, but the continued development of engineering ingenuity necessary to meet the demands of modern reservoir performance and conservation practices.

A report (39) by the Sub-Committee on Unitized Oilfield Conservation Projects of the Secondary Recovery and Pressure Maintenance Committee of the Inter state Oil Compact Commission shows that 779 projects are in operation in 16 oil and gas producing states. The total oil produced during 1958 was over 357 million barrels.

Emery (39) has re-stated the general opinion of petroleum engineers and the oil industry that the advantages of unit operation outweigh the disadvantages resulting from the loss of individual control of the properties. He discusses unitization of two types of, properties which involve engineering considerations. The first relates to unitization of producing properties and the second, less familiar to engineers, is the unitization of lands for the purpose of drilling exploratory wells. Unitization is usually the first step in the initiation of secondary recovery operations or improved production practice. For undeveloped properties, a first objective is the completion of the development program in an orderly manner. A second objective is to insure efficient primary and often secondary recovery.

Optimum-drilling and Optimum-building of pipelines, plants, storage and other related facilities are realistic objectives of unitized operations. The necessary and important reservoir energy is conserved. Unnecessary and excessive costs are minimized. Whereas property lines control drilling without unitization and the existing law of capture as applied results in early peak production and costly excess capacities in facilities, the alleviation of these disadvantages through unit operations is a common observation.
Petroleum Supply and Demand
Authors: Warren J.E.
Published: December 2007

This paper discusses the functions - production, transportation, processing and marketing - required to supply petroleum in response processing and marketing - required to supply petroleum in response to the demand generated in the markets of the free world, and it emphasizes their interdependence. It also appraises the political, economic, and technical factors that have recently caused significant changes in the historical supply-demand pattern. Finally, it attempts to project future trends in supply and demand.

Introduction

In February, the Los Angeles area suffered a severe earthquake - over 60 people were killed, and property damage amounting to several hundred million dollars was incurred. This earthquake was not predicted although many scientists were actually making local stress measurements for that specific purpose. The principle reason for this failure was that, the quake was caused by principle reason for this failure was that, the quake was caused by movement along the San Gabriel Fault - not along the San Andreas Fault, where the measurements were being made. Following the major quake, after shocks were felt for several months before a state of unstable equilibrium was finally attained. This seismic phenomenon, in a very real sense, has its analog in the international petroleum industry; i.e., we can observe the stresses that are present, but we can predict neither the location of the epicenter nor the intensity of the shock. Stresses were evident last fall in Libya, the Arabian Gulf and Venezuela; however, the major disturbance did not occur until the Organization of Petroleum Exporting Countries (OPEC) confronted the major international oil companies in Teheran during February of this year. Aftershocks have since been felt in Libya, Venezuela, Nigeria, Algeria, and elsewhere. As a result of these shocks, the roles of the major international oil companies, as well as those of the producing and consuming countries, have been drastically altered - OPEC has assumed the initiative; the influence of the majors has begun to decline significantly and the importing countries have started to react. These changes will affect pricing, price stability and, ultimately, energy policies throughout the world.
The Use of Pressure Buildup information to Analyze Non-Respondent Vertically Fractured Oil Wells
Authors: Evans John G.
Published: December 2007

When a hydraulically fractured oil well, with a single vertical fracture, does not respond favorably to the stimulation treatment, and provided that well conditions warranted the frac treatment, the cause of poor response is due to flow restrictions within the propped fracture, an unpropped fracture, or a damaged region in the formation adjacent to the face of a propped fracture. By the proper analyst of pressure buildup data taken from the we pressure buildup data taken from the we location of the flow restriction can be determined. Linear flow into the fracture distinguishes formation damage from either an unpropped fracture or from restrictions in a propped fracture. Approximations of the propped fracture. Approximations of the fracture length and thickness of the damaged region near the fracture face are available by using the techniques presented.

Introduction

The production performance of an oil well following a hydraulic fracturing treatment often continues on pre-stimulation decline trends, does not return to prior levels, or improved rates are not sustained. Providing that well conditions warranted the fracture stimulation, the causes of the unfavorable results are either due to flow restrictions within the propped fracture, an unpropped fracture, or a damaged region in the formation adjacent to the face of a propped fracture.

When the fracture is vertically oriented and when negligible or zero flow occurs in the fracture, the fluids flow radially into the wellbore from the surrounding formation. If the formation near the fracture face is damaged, then the flow near the propped fracture is essentially linear. Thus, recognition of the type of flow near the well determines the condition causing reduced flow rates, i.e., either 1) plugged propped fractures or unpropped fractures, or 2) formation damage adjacent to the propped vertical fracture.

A method is presented herein for the identification of the flow regime near the well from pressure buildup data. Approximations of the fracture length and thickness of the damaged region near the fracture face are available by using the techniques presented.
Improved Paraffin Prevention Techniques Reduce Operating Costs, Powder River Basin, Wyoming
Authors: Bummer Bruce L.
Published: December 2007

This paper presents and discusses the methods used by Amoco Production Company to reduce operating costs resulting from paraffin deposition. The initial program was basically that of removal of paraffin deposits from downhole tubular goods and surface lines and equipment by mechanical cutting and oil treating. However, as production experience was gained, it production experience was gained, it was established that the prevention of paraffin deposition was much less costly than its removal. Hence, plastic coated tubing and rods, plastic coated tubing and rods, fiberglass flow lines, and paraffin inhibition chemicals were investigated and eventually utilized extensively. Since then mechanical cutting and hot oiling to remove paraffin deposits have virtually been eliminated with a concurrent reduction in operating cost.

Introduction

The Powder River Basin (Figure 1) has developed into one of the most prolific oil and gas producing basins prolific oil and gas producing basins in Wyoming. Prior to 1967, Powder River Basin production occurred primarily from the Minnelusa formation primarily from the Minnelusa formation (Pennsylvanian age) which yielded a black asphaltene base crude and very little gas. The discovery of Bell Creek Field in 1967 in the Muddy formation (Cretaceous age) resulted in a rush to find Muddy oil and gas. Muddy production in the Powder River Basin has risen from approximately 6,000 BOPD in 1966 to in excess of 100,000 BOPD currently. Muddy oil is generally a high gravity paraffin base crude. Solution gas-oil ratios range from 500 to 1500 SCF/BO. One of the most significant operating problems associated with muddy problems associated with muddy production is paraffin deposition.

PARAFFIN AND ITS DEPOSITION A paraffin problem can basically be described as the formation of an organic deposit in oil producing equipment such as tubing, flow lines, manifolds, separators and tanks.
Design Charts for Estimating Swept Areas After Breakthrough in Flooding Heterogeneous Reservoirs
Authors: Pitts Gerald N. , Crawford Paul B.
Published: December 2007

A study has been made and a series of charts are provided so that one may estimate the swept areas after breakthrough in flooding or cycling heterogeneous reservoirs. It is well known that reservoirs are not uniform and homogeneous, nor do they exist in uniform layers without crossflow, yet, the working charts and figures available to the engineer assume uniformity of the rock from an input well to an output well.

A series of charts has been developed various flooding patterns to show the swept areas after breakthrough for the case in which the rock is heterogeneous in nature, and the heterogeneity is distributed at random within the rock matrix. To use the charts one makes a plot of the permeability distribution data for the field and then refers to a figure in the paper to find a permeability distribution data paper to find a permeability distribution data nearest that of the real reservoir from this figure one then refers to the proper pattern such as five-spot or direct line-drive to find the expected areal sweep at breakthrough and performance afterward to depletion.

Introduction

Commencing about thirty years ago a number of methods have been presented in the literature for estimating the performance, area swept at breakthrough and after breakthrough for waterflooding and pressure maintenance programs.

In the early analytical work Muskat reported on the calculated sweep efficiency. His work showed the sweep efficiency for the five-spot and direct line-drive, square pattern, to be of the order of 72 percent and 56 percent, respectively. Muskat's calculated percent, respectively. Muskat's calculated results were based on a uniform homogeneous rock, fluid mobility ratio of one, gravity effects were neglected and capillary effects were neglected. His work has served as the basis for many computations.

An unusually fine paper on engineering waterfloods was presented by Herman Dykstra and R. L. Parsons at the May 1948 API Meeting in Los Angeles. In the Dykstra Parsons method it was suggested that a straight line may result when the cumulative percentages of samples were plotted against the logarithm of the permeability.
Predicting Water Flood Performance by Analogy
Authors: Slider H.C.
Published: December 2007

Introduction

Most engineering design work is done by analogy-at least in part. If your engineering supervisor asks you to design a hydraulic fracture treatment for a particular well, undoubtedly your first reaction will be to pull the well files on similar wells that have been hydraulically fractured in that reservoir and design the treatment along the lines of the past successful hydraulic fracture treatments, modified for the particular peculiarities of the subject particular peculiarities of the subject well. Most engineers would agree that this approach would give a much more effective treatment than would the more theoretical approach of simply designing the fracture treatments based on the reservoir parameters and the engineer's theoretical knowledge of hydraulic fracturing. The justification for engineering by analogy is simply that it is invariably more accurate than engineering design based strictly on theoretical considerations. The accuracy is of course a function of the similarity of the model (the old design used as the analogy basis) and the proposed design. The use of empirical data is of course a type of prediction by analogy.

It is not always obvious as to how the results of a previous project can be used to predict the results in a proposed project. Ideally the model proposed project. Ideally the model and a proposed flood should be exactly the same; then results would be exactly as predicted. However, this is never the case. When the results of a previous flood are used to predict the previous flood are used to predict the results of a proposed flood, we are invariably faced with many differences in the two projects. These include differences in size, percent of injection lost outside the swept area, injection pressure, reservoir capacity, the state of depletion, mobility ratio, permeability profile, etc. It is permeability profile, etc. It is impossible to account for variations in all of these factors.