bluuebunny/crossref_metadata_2025 huggingface dataset:
Some Economic Considerations of Underground Coal Gasification
Authors: Jennings J.W.
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.

The economics of the use of underground coal gasification to supply the fuel for a combined-cycle power generation plant are studied. Much of the data relative to the underground process was obtained from the experiment being process was obtained from the experiment being conducted by the Energy Research and Development Administration (E.R.D.A.) (previously the U.S. Bureau of Mines) at Hanna, Wyoming. The capital and annual operating monetary requirements are estimated for a 1000 MW, on site, combined-cycle power plant.

The sensitivity of the required selling price of the generated electricity to various price of the generated electricity to various operating parameters such as well spacing, coal seam thickness and depth, and producing rate are presented. The required capital for a 1000 MW plant producing from a 70 ft. thick seam of coal at a depth of 2000 ft. is estimated at $165 million. The annual operating cost of such a plant would be about $13 million and could profitably sell the generated power at 7.5 mils/ profitably sell the generated power at 7.5 mils/ KW-hour.

Introduction

Interest in underground coal gasification as a potential energy source in the nation has increased greatly over the last several years. The reasons for this renewed interest are many. The growing energy demand, the decrease in availability of more conventional energy sources and magnitude of the potential coal resource in this country are but a few of these reasons. It is apparent that underground coal gasification, if feasible, could be a process capable of producing vast quantities of clean fuel particularly suited for use in combined-cycle particularly suited for use in combined-cycle power generation. power generation. The use of combined-cycle power plants fueled by gas generated in surface coal gasification plants has been the topic of several papers in the recent past. Even more recently, several natural gas-fired, combined-cycle plants have been installed, typical of which is a 240 MW plant built for the Public Service Company of Oklahoma near Lawton, Oklahoma. These plants are particularly suited as low in capital cost, low polluting generating stations for supplying intermediate power loads. power loads.
Geological And Drilling Aspects Of Columbia's Mingo County Prospect
Authors: Gates Frank A. , Watson W.A.
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

Columbia Gas Transmission Corporation's Well 9674-T was located and drilled on the North Kermit Prospect on Mineral Tract No. 10, in Harvey District, Mingo County, West Virginia. (See Fig. 1).

The North Kermit Prospect is situated on the south flank of the Rome Trough in association with a major northeast-southwest trending down-to-the-north basement fault (see Fig. 2). It was anticipated that a southern platform, located south of the major fault would have been exposed to erosion during the formation of the trough resulting in deposition of clastic units adjacent to and north of the fault. These units would then have acted as reservoir beds. This supposition was based on seismic data, structure and stratigraphy observed along the northern hinge line.

Well 9674-T had as its primary objective the testing of the Rome and Basal Sand formations with a secondary objective of testing all units below the Tuscarora Sandstone.

Seismic data indicated structural closure of 600 feet against the fault on the basement surface. A closure of 200 feet was indicated near the top of the Rome.

The Rome was expected to contain massive marine sandstones with interbedded dark shales and some limestones. Both lenticular and blanket type sands were expected north of the fault, affording structural and stratigraphic possibilities, with maximum sand development along the fault scarp. The well was spudded on September 30, 1971, and was the first of several wells which have since been drilled to basement within the deeper portion of the Rome Trough.

The well was drilled by Loffland Brother's Rig 111 which is capable of drilling below 20,000 feet (see Fig. 3). Rig 111 was located near Laurel, Mississippi, and it required 14 days to move to the location.

Due to terrain, the well site was 140 × 200 feet, rather than the recommended 400 × 400 feet. The location was surrounded on three sides by a creek which could not be relocated.
Recent Oil and Gas Activities in Tennessee
Authors: Statler Anthony T.
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

The 1969 discovery of Tennessee's first million-barrel field, Oneida West in Scott County, has resulted in a significant increase in the state's drilling activity and production in the last 5 years. This Mississippian carbonate play, centered in the Northern Cumberland play, centered in the Northern Cumberland plateau region, has resulted in several plateau region, has resulted in several good Ft. Payne limestone discoveries trending northeast through Scott and Morgan Counties. Several lesser finds have been made in the younger Monteagle and Bangor limestones. A number of scattered potential shallow gas wells have been drilled and shut-in, but little data is available on reserves. Marketed gas remains insignificant largely because of lack of pipeline facilities.

Mississippian pays are found depths of less than 2000 feet, and most fields appear to be stratigraphic traps with little or no relationship to structure. The better Ft. Payne fields are gas cap and gas-solution drive reservoirs with no producible water.

In 1974 crude oil production totaled a record 768,700 bbl, a sizeable increase from the previous year due largely to the Ft. Payne discovery at Indian Creek in late 1973. Field operators are initiating a repressuring program for this reservoir. Cumulative production from Indian Creek should reach a million bbl near the end of this year.

Several deep tests drilled in this part of the state have found porosity and gas shows in the Copper porosity and gas shows in the Copper Ridge section of the Knox Group. However, the premississippian horizons which may have potential in eastern Tennessee still remain largely untested.
Coiled Tubing Injection String for Geothermal Wells
Authors: Alescio Salvatore , Ricciardulli Roberto , Vallini Alessandro , Caponi Nicola
Published: December 2007

Geothermal wells are constantly producing extremely hightemperature steam and endogenous fluids containing corrosive substances.1 These corrosive substances are detrimental to completion, surface, and processingplant materials. In addition, geothermal wells contain high percentages of dangerous gasses, such as hydrogen sulfide (H2S), requiring operators to take special safety precautions. When coiled tubing (CT) injection strings are used to complete such wells, equipment and surfaceplant damage caused by corrosive geothermal fluids can be significantly reduced. Conventional methods require well cleanup operations at regular intervals, but CT provides a permanent installation that allows corrosioninhibiting fluids to be injected continually, thus neutralizing the chlorides produced from the steam. Consequently, operational costs are reduced, lost production time is avoided, and the need for workover interventions is decreased. In addition, because CT is continuous pipe without joints, it provides operators with a greater degree of safety when they work on wells under pressure.

This paper discusses the techniques, wellhead equipment, and bottomhole assembly (BHA) used to install CT injection strings in several geothermal wells in Italy. The technical aspects of some of the 15 wells already completed by this method are also discussed. In addition, ideas for improving future geothermal well completions are presented.
Dielectric Constant Logging, A Salinity Independent Estimation of Formation Water Volume
Authors: Meador Richard A. , Cox P.T.
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.

A knowledge of the dielectric constant of earth materials provides a potential method of directly measuring formation water saturation. Dielectric logging has been studied theoretically and experimentally in order to supply this valuable knowledge. Laboratory core measurements, theoretical borehole-system computer models, instrument design and a detailed field example are combined to illuminate the concepts and demonstrate the value of dielectric constant logging.

Introduction

An open hole logging method which directly distinguishes oil from water in formations having low or unknown water salinity has been needed for many years. A potential technique for solving this problem relies upon a determination of the dielectric constant of the formation. Dielectric constant is a basic electrical property of matter for which oil and water have distinctly different characteristics. It is measured in units of farads per meter.

It is well known that resistivity log interpretations are dependent upon a knowledge of formation water salinity. Unknown or variable salinity often leads to ambiguity in the log interpretation. Dielectric constant measurements can circumvent this problem because the formation dielectric constant is primarily determined by the water volume, not the water salinity. Large water volumes produce high dielectric constant values, and small volumes produce low dielectric values. produce low dielectric values. Efforts to build logging systems which measure formation dielectric constant have been underway. Russian scientists have been active in this field for several years and have published papers on the subject. published papers on the subject. The various aspects of dielectric logging have been discussed separately in these publications.
Production Management Of Reservoirs Through Log Evaluation
Authors: Smith R.L. , Patterson W.F.
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.

This paper describes a complete computer analysis technique which can be used to evaluate a reservoir periodically throughout its lifetime. The resulting periodically throughout its lifetime. The resulting presentation provides the production manager with presentation provides the production manager with heretofore unattainable data that can lead to more efficient reservoir exploitation and better planning of remedial workwover.

In the Gulf Coast it has provided quantitative depletion data. It can also detect many production problems, including: problems, including:*water encroachment and coning*bypassed production*vertical barriers*blocked perforations*premature water breakthrough
Comparison of Performance During Cycling and Blowdown with Various Prediction Methods-Washington Cockfield "D" Gas-Condensate Reservoir
Authors: Elkins L.F. , Brown R.C. , Skov A.M.
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.

Performance of the Cockfield "D" sand gas condensate reservoir during cycling and subsequent blowdown is compared with calculations using the conventional layer model assumptions. Actual performance during cycling was better than that calculated using the Dykstra-Parsons and Stiles techniques of determining permeabilities for layers (adapted by analogy from their permeabilities for layers (adapted by analogy from their waterflood prediction methods) but not as favorable as that calculated by the Miller-Lents technique of determining such permeabilities from core data. Comparison of calculations with a similar layer model with actual performance indicates that permeability profile effects continue to be important in determining condensate content of gas produced during blowdown of the reservoir following cycling.

Introduction

The Cockfield "D" sand in the Washington Field, St. Landry Parish, Louisiana, was found to contain gas-condensate by the completion of the Thistlethwait Land and Cattle Co. No. 1 at a depth of 9313 feet in December 1951. Subsequently 18 producing wells and 6 dry holes have defined the extent and geologic characteristics of this reservoir. Limited volumes of gas were sold from November 1953 to May 1955 to determine performance characteristics of the reservoir. performance characteristics of the reservoir. The field was shut-in until unitization was achieved and facilities installed for gas injection. Cycling operations were started in October 1956. Gas injection was continued until October 1967; then gas was sold until April 1975 when the reservoir was shut-in for conversion to gas storage for a major gas-pipeline system.

The primary purpose of this paper is to compare the actual cycling performance of this reservoir with published prediction techniques. The concepts of flow in stratified reservoir rock systems during gas injection are also extended to the post cycling period - an area of technology just barely mentioned in petroleum literature. This is important in the economic decision of when to stop cycling and to start blowdown of a gas-condensate reservoir. Other aspects of reservoir performance discussed include an early long time injection-production interference test conducted to aid in selection of the tall pattern used for cycling, and a comparison of volumetric estimates of gas-in-place with actual production.
Reservoir Simulation Design of a Waterflood with Crestal Gas Injection - Caranda Field, Bolivia
Authors: Van Kirk Craig W.
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.

Caranda is one of the largest and most complex oil fields in Bolivia. A recent reservoir-simulation study of the Taiguati "G" Este reservoir has resulted in the conclusion to initiate water injection at the oil-water contact to supplement the existing crestal gas injection program. This study also improved the understanding of the performance of other reservoirs in the field, representing a prime example of additional and unexpected benefits that frequently result from a detailed simulation study.

Introduction

This is a presentation of the results of a reservoir-simulation study of the Taiguati "G" Este reservoir in the Caranda field in Bolivia. The purpose of this study was to update a previous reservoir-simulation study conducted previous reservoir-simulation study conducted during 1972. The current study encompassed a description of the physical system, a match of the observed production history through June 1974, and predictions of the future performance of several different operating schemes.

The reservoir simulator used in this study is a three-dimensional, three-phase mathematical model that accounts for the effects of capillary pressure, relative permeability, gravity, and pressure, relative permeability, gravity, and variable reservoir dip. The reservoir fluids are described by pressure-volume-temperature relations. A large high-speed digital computer was used for performing the calculations in the model.

The Caranda field is in the major oil producing region of Bolivia, as shown in Fig. 1, and is located approximately 35 miles northwest of the city of Santa Cruz.

The field was discovered in 1960 with the major oil reservoir being the Permian Taiguati "G" Este at a depth of approximately 6,000 ft. Production began in early 1966, reaching a Production began in early 1966, reaching a maximum rate of 6,700 STBO/D during 1968, and has since steadily declined to the present rate of 1,800 STBO/D from 12 producing wells.

This update study has been based on a major geological reinterpretation done by Yacimientos Petroliferos Fiscales Bolivianos (Y.P.F.B.) Petroliferos Fiscales Bolivianos (Y.P.F.B.) since the last study in 1972. Also included in the update study are the production and pressure data gathered during the interim 2 years.
Past and Predicted Future Performance of Hassi Messaoud Field, Algeria Under Gas and Water Injection
Authors: Dorsey J.B. , Litherland J.G. , Saadi A. Ait , Boutalbi A.
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.

Past and future predicted performance of Hassi Messaoud oil field is discussed. One of the larger fields in the world, Hassi Messaoud had 38 billion barrels of highly undersaturated oil originally in place. The field has been producing since 1957, and its performance is of particular interest because of the high-pressure, miscible, gas-injection program that has been in operation for the last 11 years. Field performance is described, and future operating plans for the field are discussed; these plans will include the drilling of 500 new wells, expansion of the gas-injection facilities, and initiation of large-scale water-injection operations. A technique used to predict future performance of the field under the proposed operating plan is also presented. presented

Introduction

The Hassi Messaoud field is located in the Sahara Desert of northeast Algeria approximately 350 miles southeast of Algiers (see Fig. 1). Hassi Messaoud is Algeria's largest oil field and ranks as one of the largest fields in the world with respect to in-place oil reserves. Discovered in 1956, it has a productive area of over 1,000 square miles and produces a current 580,000 B/D of oil from 300 wells.

The oil was highly undersaturated at original reservoir conditions, and laboratory work done in the early stages of development revealed it to be miscible with high-pressure gas injection. A pilot program using high-pressure gas injection was therefore initiated in 1964; the program has since proved successful and has been gradually expanded, and plans are now underway for further enlargement. Water injection and alternating gas- and water-injection pilots are also operating, and plans are being made for expansion of the plans are being made for expansion of the water-injection program. From numerous studies, a depletion plan for the field has been evolved which will employ both high-pressure gas and water injection; with the drilling of 500 additional wells over the next 10 years, the depletion plan will permit production from the field to be increased 50 percent over its current rate.

The purpose of this paper is to review field performance to the current time and to present plans performance to the current time and to present plans and study results for use in future exploitation of the field.

GEOLOGY and RESERVOIR ROCK PROPERTIES

The Hassi Messaoud reservoir is Cambro-Ordovician in age and is comprised of a highly siliceous, cemented quartzitic sandstone overlain by beds of shaly Triassic sandstone. Figure 2 is a type log through the producing section and shows the three sand members that comprise the reservoir.
Reservoir Engineering Design of a Tertiary Miscible Gas Drive Pilot Project
Authors: Faulkner Barry L.
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.

Information relative to the design and implementation of a tertiary miscible gas drive pilot project, located in West Texas, is presented. This pilot was initiated to test the carbon dioxide multiple contact tertiary miscible displacement technique utilizing acid gas (71% CO2, 29% H2S) as the miscible fluid. Pilot sizing and evaluation approach, operating considerations, and data collection aspects are briefly discussed.

The primary scope of this presentation is the use of a streamline numerical miscible displacement program to match the classical secondary waterflood performance of this pilot and to predict and design the tertiary pilot and to predict and design the tertiary miscible gas phase as to slug size, gas water ratio, buffer slug size, and number and size of cycles.

Introduction

Improved recovery pilots are recognized as a vital step in the development of methods for recovering the vast amounts of oil remaining in reservoirs after secondary recovery. The use of carbon dioxide as a tertiary miscible solvent has the advantage of low fluid costs and therefore warrants particular attention. It has been established that carbon dioxide can provide miscible type displacement under appropriate conditions. While only limited laboratory information is available on the carbon dioxide multiple contact tertiary miscible displacement technique, laboratory tests have demonstrated that this improved recovery method is equally effective under secondary and tertiary modes. However, direct application of laboratory information to actual field endeavors has severe limitations, and only field testing in a total reservoir environment can demonstrate the operability and provide information on practical problems that must be solved before an economical tertiary recovery method is developed for an entire field. Therefore, a site for a pilot test of tertiary oil recovery by carbon dioxide flooding was selected in a carbonate reservoir in West Texas.

An available acid gas stream will actually be injected as the miscible fluid. Gas plant residue gas (predominantly methane) plant residue gas (predominantly methane) will be used as the chase fluid.
The Potential Of Enhanced Oil Recovery Processes
Authors: Sharp James M.
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

The results of three successive surveys of industrial and cooperative federal/industry field testing of Enhanced Oil Recovery methods are summarized. Included are industry's forecasts of potential domestic EOR production and reserves and of the relative production and reserves and of the relative potential of the various major EOR potential of the various major EOR processes. processes.

OVERVIEW OF EOR POTENTIAL

Any discussion of the "Potential of Enhanced Oil Recovery (EOR) Processes" must emphasize the word "Potential". The dictionary definition of "potential" is: "possible, but not yet realized; or, capable of being, but not yet in existence". This definition accurately describes the status of EOR processes at this time. While there is little disagreement that EOR processes promise to be an important factor in crude oil production, there is equally little production, there is equally little disagreement that this has yet to be demonstrated.

EOR technology is not yet developed to the point of permitting accurate prediction of performance and risk prediction of performance and risk assessment. Therefore, it is not ready for production-scale application. For this reason, any projection of the Ultimate Recovery or of the time frame for a given level of Annual Production to be realized from EOR processes must be based solely on informed engineering opinion. It follows, then, that projections of production costs for EOR projections of production costs for EOR crude oil cannot be made except as very approximate ranges of cost for hypothetical successful operations. Finally, a prediction of the production vs time profile and of the incremental increase profile and of the incremental increase in recovery for a specific EOR process as applied to a specific reservoir in advance of large scale field test completion may be even more suspect than projections of total domestic projections of total domestic production, since statistical averages do not production, since statistical averages do not apply.

There is, then, considerable uncertainty regarding both the technical and the economic feasibility of EOR, especially as applied to a specific reservoir.
Spontaneous Emulsification-A Possible Mechanism for Enhanced Oil Recovery
Authors: Cash R.L. , Cayias J.L. , Hayes Michael , MacAllister D.J. , Schares T. , Schechter R.S. , Wade W.H.
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

Introduction

Spontaneous emulsification will occur between a hydrocarbon phase and an aqueous solution of petroleum sulfonates if the sulfonate preferentially partitions into the oil phase. The displacement of residual oil, in phase. The displacement of residual oil, in laboratory core floods, at a small capillary number is significantly improved when spontaneous emulsification occurs; with the displacement efficiency being favored by high emulsion coalescence rates. The mechanism of oil mobilization in these displacements may distinct from those of miscible and immiscible processes. processes.

MECHANISMS OF SPONTANEOUS EMULSIFICATION

If a layer of toluene is carefully poured on top of an aqueous phase containing 3 weight-percent of a petroleum sulfonate and 1 weight-percent NaCl, the system initially consisting of two relatively clear, distinct phases is at first quiescent. After about 15 minutes, a mist of fine drops can be seen at the interface: the surface beings to twitch sporadically and an emulsion of growing proportions is observed to form. This spontaneously formed emulsion is not, however, thermodynamically stable and so it cannot be attributable to "negative" interfacial tensions. Indeed, in a matter of days, coalescence of the emulsion can be detected. Eventually, the emulsion will coalesce entirely and the two clear phases are then stable, but of different composition.

The example of spontaneous emulsification/ breaking cited above is not an isolated one; many other similar systems will be defined in this paper. What makes the above process fascinating and certainly worthy of further study is that it represents a possible mechanism for tertiary oil recovery - one that appears to have been largely overlooked: one which is distinctly different from the low tension processes. It is the purpose of this paper to explore this possibility. The paper to explore this possibility. The conclusion is that residual oil can be mobilized by spontaneous emulsification. One possible mechanism is that the small oil droplets thereby mobilized may subsequently coalesce with other ganglia of residual oil, creating a local region of enhanced oil saturation. Other mechanisms of increasing the local saturation pre, however, possible. Once the local oil pre, however, possible. Once the local oil saturation is increased sufficiently the oil will be mobilized. Further coalescence can take place, and an oil bank can be formed. This place, and an oil bank can be formed. This process has been tested and the results are process has been tested and the results are reported here.
Fireflooding Shallow Tar Sands - A Case History
Authors: Terwilliger P.L.
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

A field pilot test of forward combustion utilizing fracturing techniques was conducted in a shallow tar sand deposit in central Kentucky. The tar sand at a depth of 100 ft had an average porosity of 22%, an oil saturation of 64% (6.4% porosity of 22%, an oil saturation of 64% (6.4% tar by weight) and a permeability of about 2000 md. The tar had an API gravity of 10.6 deg. and a viscosity of 150,000 cps at a reservoir temperature of 56 deg. F. The pilot area was a small inverted five-spot which was 107 ft on a side. Horizontal fractures were created in the four producing wells by breaking down the formation producing wells by breaking down the formation with air pressure, and the fractures extended and propped to a calculated radius of 25 ft by propped to a calculated radius of 25 ft by injecting water-base, gel carrying 4–8 mesh sand. A pneumatic fracture was created in the central injection well which was held open by the continued injection of air. A down-hole burner was used to initiate the combustion zone. Oil production responded to the movement of the production responded to the movement of the combustion zone ten days after the fireflood was started. The average oil production was 24 barrels per day for the four months required to complete the test. The total oil production of 3100 barrels was 54% of 5700 barrels originally in place in the pattern area. The injected place in the pattern area. The injected air-produced oil ratio was 42,000 cu ft/bbl. The produced oil was upgraded to 14.5 API and 2000 cps at 60 deg. F compared to 10.6 deg. API and 100,000 cps for the original tar at the same temperature. The major problems encountered were the lack of complete oxygen consumption, the unsymmetrical advance of the fireflood and the tendency of the combustion zone to move toward the top of the reservoir.

Introduction

During 1959 and 1960, Gulf Research and Development Co. conducted a fireflood field pilot test in a shallow tar sand deposit lying about halfway between the towns of Brownsville and Leitchfield, Kentucky, which had been leased from the Kentucky Rock Asphalt Co., hence the name KYROCK. The fireflooding or forward combustion method has been adequately described elsewhere and the modification tested at the Kyrock site was the utilization of both pneumatically and mechanically propped fractures. pneumatically and mechanically propped fractures. Earlier reverse combustion experiments in the sand tar sand deposit had indicated that horizontal fractures could be extended at constant depth over considerable distances and that a forward combustion reaction zone could be maintained using these fractures for a major part of the fluid flow. part of the fluid flow.
Steam Mobility in Porous Media
Authors: Trimble A.E. , Menzie D.E.
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

An experimental investigation was made to study the steam displacement process. This paper presents the process. This paper presents the results of those experiments designed to show the role of steam mobility in the process. Calculations of steam phase relative permeabilities as phase relative permeabilities as functions of steam quality and liquid phase water saturation are also shown phase water saturation are also shown as an extension of the use of this type of data.

Mobility experiments were made in the absence and in the presence of a light oil. The oil was selected such as to minimize viscosity reduction and eliminate distillation. The role of steam mobility can then be seen in relation to the basic displacement efficiency of steam.

Results of the study indicate that steam mobility (in the absence of residual oil) decreases with steam quality for both high and low permeability cores. Where steam mobility permeability cores. Where steam mobility was measured in the presence of residual oil saturation, the effect of residual oil saturation became less pronounced with a decrease in steam pronounced with a decrease in steam quality and an increase in core permeability. permeability

Introduction

The principal mechanisms for the additional oil recovery from a steamflood over that of a waterflood were reported by Willman et all to be 1) thermal expansion of oil, 2) oil viscosity reduction, and 3) steam distillation of the oil. These three factors are present to various degrees in any field thermal operation and are of vital importance in trying to predict a steamflood performance. predict a steamflood performance. Shutler, using a thermal model to investigate the steamflood process, noted that oil recovery was obtained which could not be explained by temperature or steam distillation alone. He suggested a "condensing drive" mechanism was responsible.
Considerations in Financing the Development of Petroleum Resources
Authors: Matthews Thomas K.
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

I have great empathy for those of you who are daily engaged in the valuation process. It hasn't been long since our process. It hasn't been long since our principal concern, aside from the reserve principal concern, aside from the reserve estimates, was the MER and predicting the allowable days for Texas and Louisiana. Crude prices were easy, for we all expected prices would ultimately increase. In prices would ultimately increase. In addition, financial institutions were eager to lend their money for reasonably long terms at exhorbitant fixed rates of 5 1/2 % to 6 %. Certainly the Rip Van Winkle engineer of the sixties arriving on today's scene would be more than a little confused.

While theoretically the financing of estimated reserves has improved substantially, along with the computer programs and hardware, the specter of controlled prices, rollbacks, FPC expansion or prices, rollbacks, FPC expansion or contraction, inflation, taxation, tight money, and OPEC, tends to fog the crystal balls of the heretofore competent prognosticators. I am sure that many of you have become as proficient in hedging your evaluations as proficient in hedging your evaluations as economists propounding future economic events.

Regardless of today's uncertainties, oil and gas will be the dominant energy sources for some time to come, and national priorties require an economic framework which encourages accelerated development of oil and gas reserves. The current outlook indicates that the sustained investment required to develop new reserves will substantially exceed the internally generated cash flow of the industry. Increased debt will be required to fund a good portion of the shortfall. We will unquestionably be called upon with more frequency to provide economic projections related to financial requirements.

The type of financing you are most likely to be concerned with is project financing, where the funds are borrowed for development of a specific project, and repayment is based solely on revenues resulting from the completed project. Project financing has come into much wider use in the past few years for several reasons, not the least of which is the favorable balance sheet treatment it affords.
The Relative Cost of Major Project Delay
Authors: Gaffney P.D. , Cox T.F.
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

This paper discusses the interplay of the more important factors which determine an optimum development plan. Practical considerations may dictate an early commitment to field development, particularly in an offshore environment but such decisions must rely on a precise balancing of the relative advantages and disadvantages incurred by any delay.

Early commitment involves heavy reliance on relatively sparse reservoir data and it is therefore necessary to reconcile this drawback with the benefits of earlier cash flow. This assessment takes account of two additional factors, namely the effect of changes in oil price and the rate of inflation applicable during the investment period. The application of a lower initial period. The application of a lower initial investment exposure in a development plan within a high-risk reservoir environment shows that while this approach may not result in the most profitable field venture in the longterm, it frequently makes possible the initiation of a field project which would otherwise remain dormant.
Flow Closing Coefficients from Water Flow Tests for Subsurface Controlled Safety Valves (API-SSCSV's)
Authors: Pierce Phillip E. , McLemore Ethel Ward
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

Flow closing coefficients and a function for prediction of orifice size, given the pressure drop and flow rate, were derived from pressure drop and flow rate, were derived from an analysis of water flow tests made on subsurface controlled safety valves. A pressure-drop function, the mass flux function, and four pressure-drop function, the mass flux function, and four Buckingham pi-number functions, were investigated, using the test data, as possible equivalents to the Bernoulli flow equation. The Euler function gave the highest probability of minimum error in prediction of the flow closing coefficients and orifice size.

Introduction

Subsurface controlled safety valves (SSCSV) are installed down hole in the tubing by wireline. They are frequently referred to as velocity closing valves or Storm Chokes. When they are installed in oil or gas wells, their purpose is to shut the well in when a disaster purpose is to shut the well in when a disaster occurs at the surface causing the wellhead to be partially or completely removed. The sudden partially or completely removed. The sudden increase in production rate resulting from such an event causes the safety valves to close because of an increased pressure drop across the bean or choke. This increased pressure drop acting against a differential area formed by the bean diameter and a sealing element diameter produces a force that overcomes a spring force produces a force that overcomes a spring force acting to keep the valve open during normal production. production. Fig. 1 shows a common type of SSCSV usually referred to as a "poppet type". The valve is shown in both open and closed positions. It is in the open position during normal production and is closed immediately after a disaster production rate occurs. production rate occurs. Fig. 2 shows a ball-type SSCSV in both the open and closed position, and Fig. 3 illustrates a third type called a "flapper valve" in both positions. The operating principle is the same positions. The operating principle is the same for all three valves; that is, a pressure drop acting against a differential area causes a force greater than a preset spring force tending to keep the valve open, therefore the valve closes.

Fig. 4 shows the derivation of the force-balance equation. This is a general derivation and is assumed to apply to all types of safety valves although a ball type is shown in the schematic.

Fig. 5 shows the position of the pressure taps used to measure the effective or valve-closing pressure drop across the valve.
Oilwell Paraffin Prevention Chemicals (September 1975)
Authors: Fulford Richard S.
Published: December 2007

Factors that influence paraffin deposition were investigated in laboratory experiments. An apparatus was built that measures the pressure and flow rate changes caused by pressure and flow rate changes caused by paraffin deposition from crude oil in one-half inch paraffin deposition from crude oil in one-half inch diameter steel pipe. Experiments were done with and without commercial paraffin prevention chemicals to determine the effectiveness of the chemicals. Several additives altered the flow properties of the waxy crude oil and thus properties of the waxy crude oil and thus prevented paraffin deposition at cold temperatures. prevented paraffin deposition at cold temperatures. The chemicals investigated include polyethylene, ethylene co-polymers, xylene, naphthylene as well as various surfactants sold or paraffin prevention. prevention. Temperature is the most important factor in paraffin deposition, but since crude oils with high wax contents are viscoelastic the flow rate and pressure are also important. As the flow rate decreases high wax crude oils become more viscous.

Introduction

Paraffin deposition in oil fields is an expensive and time consuming problem. It has been estimated that paraffin control in the domestic production industry costs in excess of five million dollars annually. These are direct costs and do not include production losses, increased horsepower requirements, damage or increased wear to equipment and manpower attention. This estimate was made in 1969 and inflation since that time may easily have doubled this figure.

Paraffin deposits are normally attributed to cold temperatures, but evaporation of light ends and gases can also cause solids to deposit from the crude oil. Since high-wax crude oils are viscoelastic the flow rate and pressure are also important.

EXPERIMENTAL

Identification of Oilfield Paraffins

The paraffins were dissolved in heptane and separated into saturate, asphaltene ad aromatic fractures by a procedure reported by Graves and Tuggle.

Paraffin-Crude Oil Flow Experiments Paraffin-Crude Oil Flow Experiments Experimental Materials

Crude oil from two different Oklahoma fields were used.
An Environmental Research Program for Drilling in the Canadian Beaufort Sea
Authors: Hnatiuk John
Published: December 2007

A multi-million dollar environmental research program consisting of thirty-three wildlife, biological, oceanographic, meteorological, sea ice and oil clean-up studies related to the southern Beaufort Sea is described. The studies are designed to provide ecological baselines, a better understanding of the physical environment, knowledge related to the consequences of a possible oil spill and means of oil clean-up in ice-infested waters Seasonal offshore drilling in Canadian Beaufort Sea from a floating vessel has been approved in principle and is scheduled to be undertaken during the open water period of 1976. The results of the studies discussed will be used to set operating constraints to safeguard the environment and minimize any adverse impact.

A unique feature of the program is its joint government-industry nature. The studies were specified by the Canadian Federal Government but the majority of the direct funding is by the oil industry. Government agencies co-ordinate the program with considerable management and scientific input from oil industry personnel. The two-year program will be completed by the end of 1975. The hostile environment is briefly described and problems arising during one of the worst ice seasons on record are discussed. The scope of the studies research methods and progress to date in individual studies are outlined and, where possible, results are provided. An important phase of the program is public interface to inform northern natives, government, those with environmental concerns and others about the program and the study results.

Introduction

The search for hydrocarbons in Canada's North has been extended to the geologically attractive but environmentally hostile southern Beaufort Sea. During the period, 1963 to 1969, offshore permits to explore for oil and gas were issued for the majority of the continental shelf which extends some 75 to 100 miles from shore, to water depths of approximately 600 feet, shown on the location map, Figure 1.
Technical Data File and Machinery Index Aboard Offshore Drilling Rigs
Authors: Buttery L.M.
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

Offshore drilling rigs are large, complex and expensive. The amount of technical data (in the form of manuals and engineering drawings) required for rig operation is quite massive and compilation and maintenance of such data is quite difficult. This paper discusses and illustrates how the use of "keyword indexing," magnetic tape typewriters and microfilm were used to produce a technical data system that produce a technical data system that is compact and easy to use, maintain and extend to other rigs.

Introduction

Experience shows that libraries of printed manuals and drawings have a printed manuals and drawings have a short useful life aboard offshore drilling rigs and, further, that required information is oftentimes unavailable by the time a critical need for it arises.

When equipment breaks down, for example, repair instructions and spare parts lists become critically needed parts lists become critically needed information. At such a time, nevertheless, it is not uncommon to find that such information is not available aboard the rig. The result is needless delay in repair — or worse, faulty repairs — and, ultimately, additional operating/maintenance costs.

Even if the basic information source is located, documents within it are likely to be damaged from previous use or part of the material may be missing. Even if the document, itself, is located, the particular bit of data required at a given time may be difficult to find because of inadequate indexing. And even if the data required is found, the volumes containing it are usually bulky and difficult to handle at point of use. Ordinarily, no means is available for copying needed pages. As a consequence, pages are removed from loose-leaf binders for use at the job site. The likelihood of replacement for these pages is not very great. On the other hand, the probability that such pages will be probability that such pages will be damaged is fairly high. With each successive use of technical data, the chance of its availability, when next required, becomes significantly smaller.
A Modification of Carter's Equation for Fracture Area
Authors: Pattillo Phillip D.
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

The classic equation developed by R. D. Carter for the area of a hydraulic fracture assumes the width of the fracture to be everywhere uniform. The present work represents a modification of Carter's equation for the case of non-uniform width that is a function of the time that the fracture reaches a given location. An assumed form of the width function is then employed to compare the results of this paper with Carter's original work. paper with Carter's original work

Introduction

In 1957, R. D. Carter derived the classic equation for the area of a hydraulic fracture as a function of a uniform average width, fluid injection rate at the wellbore, the fluid loss rate into the formation, and elapsed time. The explicit form of the solution of Carter's equation will depend on the functional representation of the fluid loss. Due to the complexity of solving Carter's equation for some functional forms of the fluid loss, other workers abandoned this more general relation in favor of methods whereby the fluid loss function is applied directly to a particular fracture geometry.

One parameter in Carter's equation that has received only minor attention is the width which is assumed to be uniform throughout the fracture. In general, the fracture width is a function of the fracture plane spacial coordinates and time. The purpose of this study is to investigate the consequences of assuming that the fracture width at a generic point in the fracture plane is a function of time only. This assumption results in a modified form of Carter's equation which will then be compared to the original work and two of its variations in the literature.

DERIVATION OF BALANCE EQUATION

Let the x-y plane be the fracture plane (Fig. 1-a). With respect to fracture geometry, assume thatThe fracture width is symmetric with respect to the x-y plane.Concerning the loss of fracturing fluid to the formation, the assumptions of this work are tantamount to the assumptions made by Carter.Fluid flow into the formation is linear and normal to the surface of the fracture at a generic point.