bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Statistical Method for Judging the Adequacy of a Numerical Reservoir Simulation
Authors: Slater George E. , Durrer Erwin J. 
Published: December 2007

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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.
Novel Techniques Yield Savings in Hastings Field Automation
Authors: Deerhake W.F. 
Published: December 2007

Abstract
Amoco Production Company operates approximately 425 wells in the Hastings Field and in early 1969, initiated installation of a supervisory control system for the field. By incorporating a unique approach to net oil and gas measurement and use of existing lease equipment, several hundred thousand dollars were saved. Automation equipment includes a central computer, 11 telemetry units, and approximately 3000 data points at fifty sites consisting of tank batteries, salt water disposal stations, central treaters and ACT unit. Changes in the field equipment included the consolidation of 88 tank batteries into 35 sites. As much of the existing lease equipment was used as possible. Treaters were converted to three phase separators by removing the fireboxes and adding nozzles for alarm switches and controls. Capacitance type BS and W sensors and positive displacement meters were installed in the dump system of each vessel. Two phase separators were modified to three phase vessels for well testing. Central treaters were installed at the field-wide ACT unit to treat the oil to pipeline specifications.
In order to minimize costs and reduce the amount of field electronics, the net oil and gas flow computer logic was built into the telemetry equipment. The capacitance probe on each vessel provides a current signal proportional to water cut, and the positive proportional to water cut, and the positive displacement meter provides 100 pulses per barrel of fluid. The logic in the telemetry determines net oil from these input data and stores the volumes in electronic accumulators. Gas volumes are determined by scanning pressure and differential-pressure transmitters on a fixed time base and computing the extension internally in the telemetering unit.
HISTORY AND AUTOMATION OF HASTINGS FIELD PRIOR TO AUTOMATION PRIOR TO AUTOMATION The Hastings Field Automation Project includes 425 wells on 85 leases covering a 20 square mile area. About half of the wells are flowing and the remaining are on gas lift. The oil is produced from the Frio formation at approximately 6000'. The field has been producing for 35 years and has a remaining life producing for 35 years and has a remaining life in excess of 20 years. Top well allowable in the field is about 150 BOPD subject to market demand. The field is split into two segments, the west having a MER of 60,000 BOPD with a large excess capacity, and the east having a MER of 15,000 BOPD with no excess capacity. Gas is handled by the Hastings Gasoline Plant which recovers NGL and provides the necessary compression facilities. The plant handles about 55 MMCFD.