bluuebunny/crossref_metadata_2025 huggingface dataset:
The Potential "Energy Crisis" in Banking
Authors: Blanchard Robert H.
Published: December 2007

This paper was prepared for the Second Midwest Oil and Gas Industry Symposium of the Society of Petroleum Engineers of AIME, to be held in Indianapolis, Ind., March 28–29, 1974. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal provided agreement to give proper credit is made.

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.

In recent months, our eyes and ears have been bombarded with differing accounts of the energy "crisis". From the halls of Congress to the front page of our newspapers, from the public relations offices of the major energy companies to the "white papers" of the television networks, we have heard version after version of the causes and the effects of our current problem. All offer convincing explanations of the causes, and most have a proposal or two to get to the solution. It is generally agreed that new sources of energy must be found. "Self-sufficiency" has become a national, and even a state goal. Exploration and development must be increased, capital spending must be greater, lead times for plant construction must be reduced. We have a bevy of unanimous conclusions on what should be done. But few seem interested in tackling a more fundamental problem. How do we finance these ambitious goals? This is the question I would like to address today, and my initial premise is that money is really the raw material that will set the solution to the energy "crisis" "in motion". So, in that sense we both are in the energy business.

If you work for a utility, the days of financing the largest part of your company's capital expenditures from internal cash flow are gone. The days of investors eagerly receptive to utility bonds and equity issues have changed. For the oil industry, politicians are demanding taxes on "windfall profits" - not understanding or not wishing to understand the role of profit in our economy. The situation in the remainder of the seventies and the first half of the eighties will be one in which all industry and all levels of government will be clamouring for capital and you in the gas and oil industries had best begin to make your plans now, to assure that you get your needed share.

To try to place this in perspective, let's look at a few historical numbers. In the twelve years since 1960, capital expenditures of all industry increased by a factor of more than 2.4, from $37 billion to $88 billion.
Gas Lift Jet Applications Offshore Lake Maracaibo
Authors: Faustinelli Juan , Briceño Wilfredo , Padron Aaron
Published: December 2007

Production optimization in continuous gas-lift flow is achieved once the correct amount of gas has been injected through the operating valve, under stable flow condition. More than 80% of the active wells offshore Lake Maracaibo operates with artificial gas-lift methods. For this reason and because of the need to increase oil production, PDVSA E&P decided to carry out field tests using the gas jet pump concept. The pump is wireline retrievable, installed as deep as 12000 feet, with crude oil gravity ranging from 25 °API to 35 °API and for 23/8″ to 31/2″ tubing.

The need to increase the pressure drawdown in the wellbore, which increases the liquid production in already optimized continuous gas-lift wells, was done by installing a gas-lift jet pump in the circulating sliding sleeve or in the operating mandrel. The gas injected (power fluid) from the annulus to the jet orifice converts the energy, from potential to kinetic by lowering its pressure due to the area change, and creating a suction force at the throat. The production fluid and the gas injected are mixed in the throat, recovering its potential energy in the diffuser section.

The results obtained showed that this new technology could increase the pressure drawdown or liquid production up to 30% of its original oil production in some wells. It also performed successfully when a gas-lift jet pump is installed in a high gas/oil ratio sand near the production zone, having the capability to produce without gas injection (autolift). There is no field data information available on gas-lift jet pumps. It is the objective of this article to present the results and the experiences gained during the test field. Selection criteria used for well candidates are also highlighted.
Horizontal Well Performance Evaluation Tools and Techniques
Authors: Kuchuk Fikri J. , Lenn Chris , Hook Peter , Fjerstad Paul
Published: December 2007

In this paper, the use of various measurements for performance evaluation of horizontal wells is presented. First, determining formation pressure and permeability distributions along the wellbore by using the Multiprobe Formation Tester Packer-Probe Module pressure transient interval tests are investigated. It is shown that reservoir pressure measurements along the wellbore give local as well as reservoir scale information about how the reservoir is being depleted and how cleanup takes place. A few interval pressure transient test examples are presented for both formation pressure and permeability distributions. Second, a horizontal well test interpretation is presented utilizing two buildup tests from the same well conducted at different times. It is shown that uniquely determining the reservoir parameters from short buildup tests is impossible. It is also shown that minimizing the wellbore storage effect is crucial for system identification as well as for parameter estimation. Third, the productivity of horizontal wells is explored because it has been difficult to determine the horizontal well productivity due to their long length in the formation compared with vertical wells and inadequacy of measurements during drilling and production. Using field examples, we show that the new integrated production logging measurements can be used to assess horizontal well productivity by identifying productive zones, fluid entries, and determining the fluid distribution (oil, gas, and water) in the wellbore. We also show how reservoir heterogeneity affects the reservoir pressure distribution. The field examples indicate that horizontal wells have permanent water sumps, regardless of whether they produce water. In these wells, we show that when a large percentage of the wellbore cross section is filled with water, reduced oil entry occurs. Performance simulations for these horizontal well indicate 30 to 50 percent productivity reduction when they are compared with their full potential.
A Control Volume Method for Flow Simulation in Well Vicinity for Arbitrary Well Configurations
Authors: Ding Y. , Lemonnier P. , Estebenet T. , Magras J-F.
Published: December 2007

Complex wells are getting more and more used in reservoir engineering to increase the oil recovery. However, accurate modelling of these kinds of wells is still a challenge due to the scaling problem related to the large gridblocks used in the simulation and the small wellbore diameter. In this paper, a control volume method is proposed, which is suitable for the well singularity flow modelling. Both the well performance and the flux calculation in the well vicinity can be accurately handled with this method. The use of this control volume approach for complex well modelling with distorted gridblocks is particularly addressed. Some examples are presented to illustrate the efficiency of the approach.
Hydrajet Fracturing: An Effective Method for Placing Many Fractures in Openhole Horizontal Wells
Authors: Surjaatmadja J. B. , Grundmann S. R. , McDaniel B. , Deeg W. F. J. , Brumley J. L. , Swor L. C.
Published: December 2007

To date, the art of effective openhole horizontal well fracturing is not well defined. Difficulties in regional sealing hamper the fracturing task, and results are generally suspect. Without proper isolation methods, the use of openhole horizontal well fracturing is limited. During many fracturing processes, including fracture acidizing, fracture or acid placement often occurs where fluid first contacts the borehole, often at the heel of the well.

A new method is now available that combines hydrajetting and fracturing techniques. By using this new method, operators can position a jetting tool at the exact point where the fracture is required without using sealing elements. Unlike other techniques, this new method allows operators to place multiple fractures in the same well; these fractures can be spaced evenly or unevenly as prescribed by the fracture design program. Largesized fractures can be placed with this method.

Because the method is simple, operators can economically bypass damage by placing hundreds of small fractures in a long horizontal section. To enhance the process even more, operators can use acid and/or propped sand techniques to place a combination of the two fracture types in the well.

This paper discusses the basic principles of horizontal hydrajet fracturing and how Bernoulli's theorem was used to design a hydraj et fracturing technique. Laboratory test results for the new technique are provided on Page 4.
Xijiang 30-2 and 24-3 Caisson Guide Failure Analysis and Repair
Authors: Thomas Roger L. , Tai Anthony , Litton R. W. , Rodgers James , Huang Rico
Published: December 2007

On December 6, 1996, two seawater lift guides (one at the +19 foot level and one at the −40 foot level on the same caisson) and one firewater caisson guide (at −40 foot level) on the Xijiang 30-2 (XJ30-2) platform offshore South China Sea failed at the connection between the guide bucket and the standoff brace. The failed guides were missing and later retrieved from the seabed. Subsequent inspection detected cracks in other guides supporting the 24-inch caissons on both the XJ30-2 and Xijiang 24-3 (XJ24-3) platforms. Five temporary clamps (two firewater and two seawater on XJ30-2, and one firewater on XJ24-3) were installed to support the caissons at the −40 foot level to allow production to continue during the winter months. Analyses were undertaken to determine the cause of the failures and design of the final repair/strengthening to support the remaining caissons.

Analyses showed that the fatigue failure occurred due to dynamic loading caused by movement of the caissons inside the guides. Initially, wet welding permanent support members at the −40 foot level for the caissons was considered, but detailed FEA analyses of the proposed wet welded doubler plates showed high stresses in the wet welds that could cause future fatigue problems. Permanently installed clamps were designed and installed on all 24-inch caissons at the −40 foot level to replace the original guides. The +19 guides were also replaced by welding supports between the structure and the caissons. This paper will cover the conclusions drawn from the analyses of the failure, analysis of proposed repair options, the decision making process that led to the final repair solution, and the fabrication and installation of the repairs.
Application of Rock Mechanics to HPHT and Horizontal Well Drilling and Completion: A Case Study
Authors: Ray P. L. , Goodman H. E. , Perrin V. P.
Published: December 2007

An analytical technique that integrates core-based rock mechanics with openhole geophysical logs has proven valuable for Chevron's worldwide drilling and completion operations, especially for HPHT wells, horizontal wells and openhole completions. The Rock Mechanics Algorithm (RMA) uses log-derived mechanical properties for drilling and production engineering applications that include:

Formation drillability assessment for bit optimization and performance prediction Wellbore stability for horizontal and extended reach wells Sand production prediction for completion design Formation stress profile and elastic properties for hydraulic stimulation design

This study introduces the RMA program's mechanical property estimation technique and its application to drilling and completion design. Two case histories from the South China Sea will be presented. The first history involves a horizontal drilling and completion design project that includes hole stability and sand prediction and the second history involves optimal bit program and wellbore stability analyses for a HPHT well.

In the horizontal drilling and completion design project, wellbore stability was characterized in the build and horizontal sections. The appropriate mud weight to maintain hole stability was recommended. Horizontal wells were drilled successfully using the recommendation. Sanding tendency for openhole completion design was characterized over the life of the well. This analysis resulted in different completion designs for two different zones, one with an openhole gravel-pack completion and the other with an openhole completion. Up to this time, lack of sand production has confirmed the RMA prediction.

The optimal bit program and wellbore stability analysis on a HPHT well revealed that overburden, frac gradient, and pore pressure are nearly equal under the high pressure and high temperature conditions. Consequently, the safe drilling window is significantly narrowed. RMA takes into account the thermal effect and pressure effect, providing the drilling engineer with proper mud weight guidance.
A Comprehensive Practical Approach for Wellbore Instability Management
Authors: Chen X. , Tan C. P. , Haberfield C. M.
Published: December 2007

In the North West Shelf, a region of growing importance in oil and gas production in Australia, drilling delays and suspension of wells prior to reaching the targets due to wellbore instability have occurred frequently. As a result, economic benefits through the use of new drilling technologies are significantly reduced due to high additional drilling costs. In order to improve drilling efficiency and minimise drilling costs, it is crucial to develop and apply a practical approach to optimise wellbore instability management.

This paper initially presents guidelines, in the form of design charts, for efficient wellbore stability analysis and wellbore profile design. A comprehensive practical approach of using the design charts for wellbore profile design is subsequently described. The application of the design charts is demonstrated through field case studies for a range of in-situ stress regimes.
Biodegradability of Venezuelan Crude Oils
Authors: León N. , Infante C. , Arias M. , Marquez M. , Gorrín A. , McMillen S. J. , Smart D. R.
Published: December 2007

Bioremediation represents one of the most promising, cost-effective, and safest technologies to be used for the restoration of crude oil contaminated soils. However, some previous studies have shown that bioremediation is less effective for heavy, low API gravity crude oils. INTEVEP and CHEVRON have independently conducted laboratory studies to evaluate the feasibility of using bioremediation technologies for crude oils (ranging from 9 to 32° API gravity) produced by MARAVEN in Venezuela. The composition of the hydrocarbons in each crude oil was first characterized by Iatroscan, gas chromatography (GC) and gas chromatography/mass spectrometry (GC/MS) in order to better understand the potential relationship between API gravity, hydrocarbon composition, and biodegradability. Five percent (w/w) of each oil was applied to a Venezuelan loam soil and fertilizers and organic material (used as bulking agents to improve soil conditions such as moisture holding capacity, tilth, and texture) were added to the oily soil to optimize conditions for biodegradation. Abiotic controls (containing 2% v/w HgCl2 to ensure no microbial activity) and a positive control containing fertilizer, but no crude oil, were also prepared. Biodegradation was measured directly by monitoring the decreases in the percentages of saturated, aromatic, resins and asphaltene fractions via Iatroscan throughout the 4 month incubation time. The initial and final samples were also monitored for losses of total petroleum hydrocarbons by GC and polyaromatic hydrocarbons by GC/MS. Biodegradation was monitored indirectly by measuring the production of CO2, a final breakdown product of hydrocarbon metabolism. Higher microbial activity (c.a. CO2 evolution) was observed in the soil amended with light crude oils (120 mg CO2/h/m2) than in soil amended with heavy crude oils (85 mg CO2/h/m2). Iatroscan, GC, and GC/MS analyses confirmed that the light Venezuelan crude oils (>30°API) were readily biodegraded. The biodegradation potential of each of the crude oils and recommendations for which oil types are most amenable to bioremediation technologies are presented.
NMR Relaxation of Clay-Brine Mixtures
Authors: Matteson A. , Tomanic J.P. , Herron M.M. , Allen D.F. , Kenyon W.E.
Published: December 2007

Effective interpretation of nuclear magnetic resonance (NMR) logs in shaly sands requires an understanding of the NMR contribution of clays. Of particular importance is the role of clays in the rapidly relaxing part of the NMR signal.

In this study we measured the transverse relaxation time spectrum (T2) of brine mixed with four clays (illite, smectite, kaolinite and glauconite) as a function of compaction. The Larmor frequency was 2 MHz and the echo spacing 0.16 msec. Mild compaction was achieved by centrifuging the clay slurry at three successive pressures ranging from 1 to 125 psi. Highly compacted samples were produced in a uniaxial press at six sequential pressures ranging from 500 to 16,000 psi.

Each clay-brine slurry and its associated compacted sample showed a single peak in the T2 distribution spectrum. A second peak, which could be interpreted as the "clay-bound water," was never observed. The T2 peak position shifted to faster relaxation times as compaction increased, in proportion to the pore volume-to-surface ratio, V/S. The single peak and VP'S proportionality are consistent with fast diffusion between the pore water and the monolayer of water on the clay surface. Surface relaxivity varied among the four clay minerals; glauconite, the clay with the highest magnetic susceptibility and iron content had the largest surface relaxivity.

These results have important implications for the interpretation of NMR logs in shaly sands. Because of the effects of compaction and to a lesser extent the iron content on a clay's T2 peak position, it is not possible to independently determine clay type from some characteristic relaxation time. These data also imply that it is not feasible to estimate the cation exchange capacity from a single time cutoff of the T2 distribution without additional information such as laboratory measurements or other log data.

P. 205
Computational Hydraulic Analysis of a Deepwater Well Drilled With Synthetic-Based Mud in a Riserless Drilling Configuration
Authors: Lima H.R. , Juvkam-Wold H.C.
Published: December 2007

This paper presents an analysis of the temperatures and dynamic pressures occuring in a riserless-drilling-configuration deep water well by circulating a synthetic-based mud and also discusses some aspects of the effects of gas solubility on kick detection in this new configuration.

A numerical model has been developed to simulate the mud flow through the drillstring-riserless/return line system. The simulator is based on the numerical solution for the system of flow equations using finite-difference approximations. The model accounts for the pressure and temperature dependence of mud viscosity and mud density.

Through a sensitivity analysis, the effects of pertinent parameters - specially the circulation rate - on the pressures generated in the system are examined.

P. 347
Well Control Aspects of Riserless Drilling
Authors: Choe Jonggeun , Juvkam-Wold Hans C.
Published: December 2007

Riserless drilling is a term used to describe an unconventional technique using a relatively small diameter pipe as a mud return line from the sea floor instead of a large diameter marine riser. The scheme also balances internal and external pressures at the sea floor by reducing the internal pressure to make a dual pressure gradient possible.

This paper presents basic concepts of riserless drilling and a brief review of problems associated with conventional marine riser drilling for deep water applications. The paper also presents hydraulics, kick detection methods, and well control aspects of riserless drilling with comparison to conventional riser drilling. Other operational considerations are given briefly.

P. 355
Practical Application of a Multiple-Survey Magnetic Correction Algorithm
Authors: Brooks A.G. , Gurden P.A. , Noy K.A.
Published: December 2007

Conventional methods for drillstring magnetization compensation of magnetic surveys process each survey independently. Limitations of these methods include the need for an accurate estimate of the local magnetic field, while they often result in excessive scatter in corrected azimuth values and poor accuracy in attitudes near horizontal east-west.

Recent developments in survey processing include corrections which operate on several surveys simultaneously. The additional information thus obtained can be used to determine biases and other parameters affecting three axes, without the need for precise estimates of the local magnetic field strength and dip angle. Surveys processed in this way show more stable azimuth values and retain greater accuracy in the critical attitudes near horizontal east-west. The use of a multiple-survey correction technique together with in-field referencing to monitor changes in the local field addresses two major shortcomings in magnetic surveying.

Multiple-survey analysis can be used to monitor performance of accelerometers as well as magnetometers. Accelerometer variance is measured but not routinely used to make corrections when there is no significant improvement. The better practice is to use calibration values obtained in the workshop, rather than replacing them with measurements taken in the down hole environment.

The benefit of the technique is in closely monitoring sensor performance and identifying suspect surveys. Real-time verification that the tool is operating within a modeled error budget improves the value of positional uncertainty calculations. The improvement in quality control can obviate the need to run additional surveys for verification purposes.

P. 379
Retrievable Fluid Control Valve Provides Economical Placement Of Chemicals
Authors: Knox John , Hyde Walter , Scott T.A.
Published: December 2007

This paper was prepared for the Rocky Mountain Regional Meeting of the Society of Petroleum Engineers of AIME, to be held in Billings, Montana, May 15–17, 1974. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal provided agreement to give proper credit is made.

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.

Low fluid level wells constitute a large percentage of all the wells in the world. Stripper wells are more important today because of the higher price for their production. price for their production. Many types of production problems plague these wells. Because they take plague these wells. Because they take treating fluid on a vacuum resulting in short contact time or take excessive fluid, it is difficult to maintain production or to stimulate them. production or to stimulate them. A large number of chemicals have been developed to solve downhole problems but because of inadequate problems but because of inadequate placement techniques, have either been placement techniques, have either been relegated to failure or to a lesser degree of effectiveness than is expected.

Placement problems have now been solved by a new retrievable fluid control valve which is more versatile than prior tools.

This retrievable fluid control valve can permit the placement of chemicals down hole without pulling the tubing. the valve can be run and retrieved through the tubing on a wire line or dropped until it lands in the pump seat or a seating nipple placed in pump seat or a seating nipple placed in the tubing for that purpose.

This tool can also be used with packers for multiple treatments, packers for multiple treatments, allowing the packers to be moved while the tubing is full of chemical. Accurate placement of a small volume of expensive placement of a small volume of expensive chemicals is possible because the unique design permits the valve to be wide open while pumping through it, however, the column of fluid will be supported when injection stops.

A large number of field jobs with many different types of chemicals have proven its efficacy. proven its efficacy.
MER: Ultimate Recovery and Production Rate
Authors: Savage W.K. , Thachuk A.R. , Beykpour Hassan , Lohrenz J.H.
Published: December 2007

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

This paper was prepared for the Rocky Mountain Regional Meeting of the Society of Petroleum Engineers of AIME, to be held in Billings, Mont., May 15–16, 1974. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal provided agreement to give proper credit is made.

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.

Reservoir simulation studies were conducted on selected reservoirs to establish the relationship between ultimate recovery and reservoir withdrawal rate. The rates ranged from far above to far below normal production practice.

The simulation results indicate that for each reservoir and each development plan an MER curve, a curve of ultimate recovery versus reservoir withdrawal rate, can be determined given the necessary data. These curves show varying, but often pronounced, increases in ultimate recovery as withdrawal rate decreases.

The sensitivity of ultimate recovery to production rate may be affected to varying degrees by well spacing, well completion practices, fluid properties, reservoir heterogeneities, reservoir type and exploitation scheme. Results of studies on some of the parameters are presented.

Introduction

Conservation in the oil and gas industry dates back to the late eighteen hundreds and historically has dealt with the prevention of "reasonably avoidable waste of oil and gas". Legislators and conservation officials have conceived numerous means of regulating this concept. In a comprehensive review and discussion of conservation efforts by members of the Interstate Oil Compact Commission (IOCC) in 1965, it was found that the concept of MER (Maximum Efficient Rate) was a predominant method of preventing avoidable waste of oil and gas. In 1971 the federal government announced its intention to adopt MER as a means of regulating production on the outer continental shelf and in 1974 format production on the outer continental shelf and in 1974 format regulation by MER will be initiated in the form of OCS Order Number 11 which adopts the following definition of MER: "the maximum sustainable daily oil and gas withdrawal rate from a reservoir which will permit economic development of that reservoir without detriment to ultimate recovery".

It is to this definition of MER that this paper addresses itself.
Remarks by Philip L. Essley, Jr. Deputy Assistant Administrator for Policy Analysis and Evaluation Federal Energy Office Before The Society of Petroleum Engineers Symposium on Improved Oil Recovery
Authors: Essley Philip L.
Published: December 2007

Tulsa, Oklahoma

Monday, April 22, 1974

Members of SPE, Guests:

It is an honor to speak to a group of my fellow society members. Particularly at a meeting where the theme involves a subject so vital to the welfare of this country.

My purpose today is to give you some impressions of what may be ahead, and some action required, as seen from the viewpoint of a long-time petroleum engineer recently turned Washington bureaucrat.

I am sure that every member of this audience is aware that we have crossed a divide in history and are now facing a new energy watershed - that will involve new problems and require new solutions. Instead of abundant cheap energy which contributed both to the wealth of this country and our extravagant use of such energy, we now face an era of scarce, high cost energy that will require major changes in our life styles. How we handle energy will represent some key policy decisions of this decade, affecting our foreign policy, monetary policy, foreign trade, inflation, growth and employment.
A Semi-Implicit Method for Simulating Reservoir Behavior
Authors: Seth Mohan S.
Published: December 2007

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

A method to simulate multiphase flow behavior in reservoirs is presented that employes spatially varying degree of implicitness with respect to fluid saturations. By suitably defining the implicit region, the technique preserves the stability associated with simultaneous solution and computationally superior to it. Furthermore, the time truncation error is lower than a fully implicit formulation. Comparisons are presented for water-oil and 3-phase (with dissolved gas) coning systems and a gas percolation problem.

INTRODUCTION:

Multiphase flow behavior in reservoirs is described by a set of non-linear differential equations that are obtained by combining the continuity equations with the Darcy's law. These equations are generally solved numerically by variants of one of the following formulations:

1. Implicit Pressure Explicit-Saturation Method (IMPES)

In this approach the governing differential equations are reduced to a set of finite-difference equations with single dependent variable as the oil-phase pressure. Such a reduction to a pressure equation is carried out by combining the flow equation of each phase in a manner that eliminates the time derivatives or differences of saturations. The procedure treats the saturation dependent terms explicitly that include the capillary-pressures and the transmissibilities to each phase. The set of equations so obtained is solved implicitly for pressure with iterative updating of the pressure pressure with iterative updating of the pressure dependent terms. Having obtained the pressures, the saturations are computed directly from the water and/or oil flow equations. Iterative updating of the saturation dependent coefficients impairs the computing efficiency and the stability of the system. The implicit pressure entails simultaneous solution of N-equations for an N-grid-block system per iteration.

The IMPES procedure by virtue of its simplicity is amenable to a number of efficient matrix inversion techniques, and thus involves minimum computing time per time step. The explicit dating of the saturation dependent terms, however, imposes a conditional stability that limits the time steps to an impractically small size in many applications of interest. In particular, wellbore coning systems, the gas percolation and the water drainage problems, percolation and the water drainage problems, reservoirs with steep capillary-pressure slopes, etc. are difficult to simulate in the framework of IMPES, without resorting to artifices.

2. Simultaneous Solution Method (SS)

SS approach readily permits implicit treatment of the saturation dependent terms and offer a high computational stability.
An Underground Coal Gasification Experiment, Hanna, Wyoming
Authors: Schrider Leo A. , Jennings James W.
Published: December 2007

In the fall of 1972, the Bureau of Mines began an experiment to investigate the technologic, economic, and environmental considerations of underground gasification of a western subbituminous coal. The gasification site is near the town of Hanna, Wyoming, approximately 70 miles northwest of Laramie. The test results indicate that gas volumes and gas heating values have fluctuated over a wide range depending on operating conditions. The ranges have been from 50,000 to over three million standard cubic feet per day of produced gas with a composite heating value from 30 to 465 Btu per standard cubic foot. Even though these fluctuations have occurred, a semi-steady state condition existed for a six-month period. From September 1973 through February 1974 a low Btu gas averaging about 130 Btu per standard cubic foot was produced at an average rate of 1.6 million standard cubic feet per day. A material balance made during this period indicated:There was little or no underground gas leakage from the site;About 80 barrels of formation water were consumed each day;Between 13 and 46 tons of dry coal were affected each day depending on the assumptions made; andFrom 23 to 65 percent of the energy of the coal being subjected to carbonization and/or gasification is being recovered.

If the gas can be sustained at this relatively steady Btu content and production rate, it could be used directly to fire a boiler or to fuel a combined gas turbine-steam turbine cycle in electric power stations. The average amount of energy power stations. The average amount of energy produced from this small field test would have produced from this small field test would have been adequate to supply fuel for about a one megawatt power station.

Introduction

Interest in underground coal gasification has been stimulated recently by the Nation's growing energy demand. Its potential for generating plentiful supplies of fuel gas without the environmental disturbance of surface mining and without exposing workers to the hazards of underground coal mining is especially promising. While not expected to replace coal mining, it offers an alternative method of bringing the energy value of the coal to the surface. If feasible, this clean energy form could supplement the gas supply used to produce electricity, particularly in the industrial sector. It may also be possible to upgrade the gas to pipeline quality or to produce methanol as a possible substitute fuel for gasoline.

The role of oil and natural gas as sources of energy is almost as well known as the shortage of these vital fuels. More than three-fourths of the energy used in the United States in 1972 was derived from these sources. Coal, the most abundant fossil fuel, supplied only 17 percent of the Nation's energy needs in that year.
Molten Salt Processing Of Fuels
Authors: Cover A.E. , Schreiner W.C.
Published: December 2007

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

Molten alkali metal carbonates are catalysts for the gasification of hydrocarbonaceous fuels with steam. The gasification temperature can be varied by changing the melt composition so that a range of products can be made from fuel oil to substitute natural gas. Molten salt gasification can be used for processing of heavy oils and municipal processing of heavy oils and municipal refuse, for coal to SNG, clean power, clean boiler fuel, synthesis gas and ammonia. Heavy oil pyrolysis and cracking in molten salt are discussed in this paper. The status of development is given.

Introduction

The Kellogg Molten Salt Process under development for the past ten years has been aimed at coal gasification to produce a high Btu pipeline gas and a produce a high Btu pipeline gas and a low Btu boiler and gas turbine fuel. Progress on this process has been Progress on this process has been reported in various publications and is basically covered by U.S. patent 3,252,773, among others. However, initial interest at Kellogg was not for coal gasification but for heavy hydrocarbon conversion. The initial experimental work on this process was done in 1959 and is the subject of U.S. patent 3,252,774. The purpose of this patent 3,252,774. The purpose of this paper is to describe our work on the paper is to describe our work on the processing of heavy oils and to give the processing of heavy oils and to give the status of development of the molten salt process. process. PROCESSING OF HEAVY HYDROCARBONS PROCESSING OF HEAVY HYDROCARBONS It has been known for many years that alkali metal carbonates (lithium, sodium potassium) promote the carbonsteam and carbon-CO2 reactions. When equal parts of the above three alkali metal carbonates are mixed, an eutectic mixture is formed which melts at about 750 degrees F. This melting point then allows operation of a reactor point then allows operation of a reactor over a wide range of temperatures so that the products can be changed almost at will.

Shown in Figure 1 is the relationship between molten salt reactor temperature and the range of principal products when a heavy oil is the feed material. As seen in Figure 1 at 900–1000 degrees F, fuel oil, gasoline and lighter materials can be formed. At 1300–1500 degrees F, liquid products are no longer produced but ethylene-propylene are maximized.
Unitization and Additional Recovery Planning in the Jay-Little Escambia Creek Fields
Authors: Havenstrite J.J. , Hadlow R.E. , Harris R.W.
Published: December 2007

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

Within four years of discovery, the Jay-Little Escambia Creek Field was producing over 90,000 BOPD and additional recovery operations had begun under unitized operations. This paper reports the planning investment commitments and unitization efforts that brought about these achievements in this important oil discovery.

Introduction

The deep sour Jurassic trend of northwest Florida and south Alabama has been an area of intense industry activity in recent years. Since June of 1968, over 400 million barrels of crude and condensate and over 600 billion cubic feet of gas have been discovered. This paper is concerned with the Jay-Little Escambia paper is concerned with the Jay-Little Escambia Creek Field (Jay-LEC) which is by far the most significant discovery in the area with crude reserves estimated to be about 340 million barrels. Within four years of discovery, this field was unitized and producing over 90,000 BOPD. Within four days of the effective date of unitization, waterflood-pressure maintenance operations had begun. These achievements are notable examples of the benefits that can result through careful planning, vigorous investment commitment, and cooperation among all the interested parties in an important oil discovery.

Development of the Jay-LEC Field reflected an aggressive and competitive investment commitment. The second confirmation well was a three mile stepout. Sour crude production was initiated under stringent regulations within 6 months of discovery by relocating and modifying a used gas treating facility. Initial steps to construct a pipeline with capacity in excess of 100,000 BPD were taken when the field was producing less than 10,000 BOPD. The working producing less than 10,000 BOPD. The working interest owners committed to over 90,000 BOPD in treating capacity and sulfur recovery equipment within two years of discovery and entered into purchase contracts that committed over $10 million for waterflood facilities prior to agreement on unitization plans.

Additional recovery studies were planned to support specific field development needs. Preliminary evidence indicated primary would Preliminary evidence indicated primary would be low and that injection would be necessary.
A Case of the Commercial Polymer Flooding Under the Complicated Reservoir Characteristics
Authors: Deng Zhizhan , Tang Jinxing , Xie Feng , He Jinsong
Published: December 2007

According to the reservoir characteristics of H2II zone in Xiaermen oilfield, where sandstone is unconsolidated, porous and highly permeable, and formation is severely heterogeneous, even large channels exist, and oil viscosity is relatively high, a combined EOR technology of ‘high strength in-depth profile modification with ultra high molecular weight polymer flooding’ is applied to a commercial polymer flooding project conducting in this oil zone, which would finally result in an increase in oil recovery efficiency by 10% OOIP. This paper introduces the design features of the technology and analyses the field performance and phase results of the project.
Mathematical Model Simulates Actual Well Conditions In Fracture Acidizing Treatment Design
Authors: Coulter A.W. , Alderman E.N. , Cloud J.E. , Crowe C.W.
Published: December 2007

A new mathematical model has been developed which considers more of the variables encountered during fracture acidizing treatments than previous models. In particular the variables include, wellbore cooldown, temperature profile of fluid in the fracture, the fracture geometry created by both non-reactive and reactive fluids the spending of the leading edge of the acid, and the conductivity of the etched fracture faces. Productivity increases calculated by the new program correlate more closely with actual field results than those calculated by previous programs. This paper describes the previous programs. This paper describes the method of handling the variables in setting up the new model and presents the equations used to describe the reaction rate of the acid.

Introduction

Fracture acidizing has been used for stimulating wells for over 25 years. The techniques used have developed more as an art, than a science, often based on intangible ideas, rather than on predictable facts. Although a mathematical model has been available since the early 1960's, little correlation has been observed between predicted and field results. One reason for this undoubtedly was due to the use of the acid as both the hydraulic fracturing fluid and as the reactive fluid. Another was the inadequacy of the model to describe the rheological and physical properties of the fluids in the fracture. properties of the fluids in the fracture. Only when treating techniques changed, in which better results were obtained by creating the fracture with a non-reactive pad fluid ahead of the acid, was serious effort directed toward describing the conditions or properties of the fluids in the fracture.

Equations were developed first to describe the cooldown of the wellbore area, as illustrated by Ramey's "Wellbore Heat Transmission" equations in the Appendix. Then, Whitsett and Dysart, and later Sinclair, proposed methods for describing the proposed methods for describing the temperature profile of fluids within a hydraulic fracture. Hall and Dollarhide provided basic equations for considering the fracture geometry created by more than one fluid within the fracture.
Preparing the Site with Explosives to Recover Heavy Oil by Solvent Injection
Authors: Miller J.S. , Johnson F. Sam , Jones Ray A.
Published: December 2007

An explosive fracturing technique has been developed by the Bureau of Mines for preparing wells to recover heavy oils by solvent-heat methods.

A 50-ft by 50-ft five-spot pattern was drilled along with two shot wells and an observation well. Three of the pattern wells and the two shot wells were explosively fractured between 300 and 360 ft, with 15,000 lb of pelletized TNT, using wellbore shots.

Preshot and postshot cores were obtained. The preshot core indicated no fracturing of the formation, and the postshot core indicated fracturing of the formation resulting from the shooting. Measurements of permeability, porosity, water saturation, and oil saturation porosity, water saturation, and oil saturation were obtained from plugs taken from the preshot core.

Preshot and postshot airflow tests were made. Preshot tests indicated that no communication existed between wells. Postshot tests showed that communication was established between wells. The solvent injection well was chosen from results of these tests.

A postshot impression packer survey was run between the depth of 300 and 346 ft in a pattern well not explosively fractured. pattern well not explosively fractured. Wellbore irregularities obtained on the rubber sleeves indicated fracturing results from the explosive shot.

Water-injectivity tests on the four outside wells of the five-spot showed that communication had been established to the pattern wells pattern well

Introduction

This report describes a continuation of the Bureau of Mines research program on developing methods of explosive fracturing to improve the ultimate recovery of oil from tar sands and heavy oil reserves. The purpose of this research is to study the factors involved in the efficient and economic recovery of heavy oil from a consolidated sandstone petroleum reservoir by the use of explosives, solvents, and other supporting techniques.

A review of the literature revealed little information about the depth of worldwide deposits, the areal limits, or the economic possibilities of tar sands and heavy oil. Ball possibilities of tar sands and heavy oil. Ball Asso. reports 42 counties in Kansas, Missouri, and Oklahoma contain 40 percent of the recognized oil-impregnated occurrences in the United States. Many of these deposits occur at depths less than 500 ft and would be ideal for recovery of this oil by in-situ and heat and/or solvent methods.
Deepwater Riser Technology
Authors: Carter B. A. , Ronalds B. F.
Published: December 2007

The development of oil and gas reserves in water depths greater than 450 metres has seen a clear trend develop in the types of platform selected for production purposes. Floating production systems (semi-submersibles and floating production, storage and offloading facilities, FPSOs), spars and tension leg platforms (TLPs) dominate this trend.

Until recently, the use of flexible marine risers has been largely unquestioned when floating structures have been employed to develop offshore oil and gas reserves. A major advantage of using a flexible riser was seen to be its compliancy with a vessel's motion. In deeper water, however, the ratio of a vessel's vertical movement to the water depth decreases. This reduces the effective strains applied to a riser due to a vessel's motion and allows alternative riser configurations to be adopted.

Steel catenary risers (SCRs) and, to a lesser extent, hybrid risers are favourable configurations for use in deepwater for both production and export purposes. Flexible pipe is inherently expensive to manufacture and is restricted in the range of environments in which it can be employed (including high temperatures and for chemically aggressive product). The use of steel, and materials such as titanium, for these alternative configurations can overcome many of the disadvantages associated with flexible risers and offer promising solutions for marine risers in deeper water.