bluuebunny/crossref_metadata_2025 huggingface dataset:
New Technology For Conversion Of Coal To Pipeline Gas
Authors: Detman Roger
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.

The new technology for conversion of coal to pipeline gas being developed in the joint Government-Industry program is described. Status of the pilot plant operations is covered along with plans for evaluation and selection of a process for full scale demonstration. Concepts process for full scale demonstration. Concepts of commercial reactors are described along with the major problems in converting the new technology to industrial plants.

PRESENTATION PRESENTATION The nation has become acutely aware of the shortage of domestic sources of oil and natural gas. This has come about as a result of the sudden loss of crude oil from the middle East. However we do not import natural gas from the Middle East. The natural gas shortage was a growing problem for many years before the Middle East crisis. As a result of the oil embargo, the gas problem has become more acute and the urgency of developing new sources of gas has become a critical problem almost overnight. The impending problem of a gas shortage was recognized by some back in the 1950's and work was started at that time to develop processes to convert coal into pipeline gas. In 1960 the office of Coal Research was established in the Department of the Interior to direct the Government's efforts. Research to develop new processes was underway in the 60's in several processes was underway in the 60's in several organizations. These included the Bureau of Mines, Bituminous Coal Research, the Consolidation Coal Company, the Institute of Gas Technology, the Food Machinery Corporation, and others.

By 1970 several new processing concepts had been developed in the laboratories and two of these had reached the stage of pilot plant design. In 1970 a joint Government-Industry program was organized to accelerate the program was organized to accelerate the development of processes for converting coal to pipeline gas. The agreement between the pipeline gas. The agreement between the American Gas Association and the Government's office of Coal Research was for a four year program to develop promising new processes program to develop promising new processes through the pilot plant stage.
Possibilities of Energy Recovery from CO2 Reservoirs
Authors: Popp V.V. , Marinescu M. , Manoiu D. , Popp A. , Chitu P.M.
Published: December 2007

The paper presents the results of the investigations regarding thoe geothermal exploitation of CO2 reservoirs and the limited efficiency of the process.

For gas with a hydrocarbon content between 10% mol. and 55% mol., a process consisting of the catalytic burning of hydrocarbons energy recovery and CO2 injection into reservoirs is described..

P. 33
Scale Effects on Fracture Growth Resistance in Poroelastic Materials
Authors: Shlyapobersky Jacob , Issa Mohsen A. , Issa Mahmud A. , Islam MD.S. , Dudley John W. , Shulkin Yuiri , Chudnovsky Alexander
Published: December 2007

The size effect in brittle fracture of rock-type materials is studied by conducting a comprehensive experimental program with concrete specimens of different sizes from materials with different aggregates. Fracture behavior in single edge notched specimens subjected to forces, splitting and compressive along the plane, under displacement control conditions is observed. Based on experimental data and numerical analysis, the stress intensity factor and energy release rate, KIC and GIC, are obtained at the onset and in the course of crack growth. It is established that:the fracture toughness to crack initiation weakly increases with increase in specimen and aggregate sizes;the toughness significantly increases with fracture length.

These trends are attributed interaction of crack surfaces (aggregate interlock effect) due to the presence of compressive force along the crack plane. A model of the interlock effect is discussed.

P. 29
Artificial Lift Design for the Deepwater Gulf of Mexico
Authors: Stair Craig D.
Published: December 2007

Artificial lift could significantly increase ultimate recovery from deepwater Gulf of Mexico (GOM) reservoirs, but the extreme application will present unique challenges to conventional artificial lift designs. This paper presents an exploration of feasibility and operability issues for both gaslift and Electric Submersible Pump (ESP) usage in direct vertical access wells in the deepwater GOM.

System and equipment considerations for gaslift and ESP design specific to the typical deepwater GOM application are discussed. Either system will work in this application, but they will both push current technology to the limit. The incremental recovery associated with either system is shown to be largely a function of the producing gas-liquid ratio.

A description of the creation and interpretation of outflow curves for the two types of artificial lift is also included. Outflow curves are an important element in the simulation of well deliverability and reservoir performance over time. Proper use of these curves and an understanding of the curve limits are necessary to perform a valid simulation.

P. 43
Probabilistic Performance of Non-Conventional Wells in Deep Water and Amazon Jungle Fields in Brazil
Authors: Padua K.G.O.
Published: December 2007

Non-conventional wells such as horizontal, highly deviated and multilateral wells are becoming more and more common. Their customary advantages over conventional wells are usually demonstrated based on the deterministic comparison of their production and economic forecast.

However, uncertainties about reservoir (size, permeability, porosity, etc), well characteristics (length, radius, etc) and operational factors (wellbore pressure, damage, etc) yield in fact a probabilistic distribution of production and economic forecast which only on average is approximately represented by the deterministic approach.

This paper presents the development and application of a mathematical and computational model which accounts for the above uncertainties and yields a probabilistic function of the production and economic advantage on using non- conventional wells over conventional wells.

The production and economic forecast is based on simplified analytical solutions such as productivity index and decline curve. Uncertainty is accounted by means of Monte Carlo simulation based on probabilistic distribution function.

The model has been applied in potential areas in Brazil for screening purposes and has helped ranking prospects on the basis of their appropriate risks/rewards. The results show a probabilistic distribution of productivity improvement which compares satisfactorily with that presented by Beliveau.

The model has also been applied in areas partially developed with non-conventional wells for accounting prediction performance. Comparison with actual wells drilled in Brazil (more than 40) suggests a probabilistic distribution not fully developed, probably due to the small number of wells considered.

The overall results suggest that the performance expectation of non-conventional wells over conventional wells, because of the inherent uncertainty of the business, is also dependent on the number of wells drilled.

Technical contributions involve the development and application of a probabilistic approach to non-conventional production performance estimate which leads to better risk assessment and results evaluation.

P. 187
A Practical Method for Evaluating the Merit of Information
Authors: Enderlin Milton Bock
Published: December 2007

If reservoir evaluation is to reflect reality, then the information populating the models and simulators must be of highest possible merit. The merit of the input information foretells potential merit of the output. Therefore an evaluation of the input's merit can provide an insight into the potential validity of the modeling and simulation effort.

Information is derived from data by the application of knowledge. In complex exploration and development projects information evolves in a cyclic manner such that one person's information becomes another person's data. The record of data-to-information conversions from initial measurements to final information is a "chain of custody" or "audit trail." Without a "chain of custody", the associated information is without merit.

The merit of the final information is also strongly controlled by the merit of the initial measurement. Merit of initial measurement is a function of precision and a "traceable calibration" of accuracy. Both precision and accuracy must be known in order to have information of the highest merit. If an initial measurement lacks precision, then the derived final information is only predictive in nature. To assess the merit of predictive information, knowledge of a "history of predicted outcomes" is required.

This paper presents a practical approach for evaluating the merit of information by classifying it as high, medium, low, lowest, or without merit. "Chain of custody", precision, accuracy, and "history of predicted outcomes" are the discriminators. Application of this (or another similar) method will provide understanding of the output validity of the model and simulator, which will in turn measure the reservoir evaluation

P. 197
Proppant Transport Characterization of Hydraulic Fracturing Fluids using a High Pressure Simulator Integrated with a Fiber Optic/LED Vision System
Authors: Shah Subhash N. , Asadi Mahmoud , Lord David L.
Published: December 2007

Slurries of selected hydraulic fracturing fluids such as 40 lb/Mgal HPG linear gel and borate-crosslinked 35 lb/Mgal guar gel were evaluated to characterize their proppant transport properties using 6 ppg 20/40 mesh sand. In addition, fluids such as water, 40 lb/Mgal HPG linear gel, and borate-crosslinked 35 lb/Mgal gel were evaluated to determine their relative ability to remove the fluidized layer lying along the top of settling proppant bed and to subsequently erode the more compacted layers below.

The experimental study utilized a unique high pressure parallel plate flow cell, simulating a downhole fracture, integrated with a vision system of fiber optic and Light Emitting Diodes (LED). The vision system was used to quantify proppant transport characteristics and to study various aspects of proppant transport including bank buildup. Selected hydraulic fracturing slurries were pumped into a high-pressure flow cell having a 0.375" fracture gap width. The slurries were pumped through 3000 ft of 1.188 in. ID coiled tubing, 500 ft of 2 in. ID heat exchanger, and a 2.75 in. inlet manifold that could be configured to represent a wellbore having various perforation arrangements. Slurries were pumped for a selected time at a fixed shear rate in the range of 60 to 120 sec to observe the rate of bed sedimentation. These initial slurry injections were followed by various fluids and slurries to assess the degree of compaction within the previously deposited bed.

Data analysis indicates that slurry sedimentation in polymer solutions follows a non-linear relationship with time at a fixed shear rate and that perforation configuration affects proppant transport, bed height growth, and proppant bed wash off near the wellbore. It is also shown that bed height growth is not directly proportional to shear rate. Results from the current study also show that the fluidized layer along the top of the proppant bed is easily removed by a clean crosslinked gel. However, erosion of the more compact underlying layers was found to depend on a number of factors. Among these factors are the type of slurry which formed the deposit, the type of fluid or slurry being used in an attempt to erode the bed, and the total pumping time devoted to eroding the bed.

P. 253
Multipurpose Wells: Downhole Oil Water Separation in Your Future
Authors: Stuebinger Lon A. , Elphingstone Gerald M.
Published: December 2007

Promising new technologies that are being advanced have the potential to reshape development strategies in your fields. It is not always necessary to dedicate wells to production or injection; now, both functions can be performed within one multipurpose wellbore. Technologies exist to reduce water-handling volumes at the surface by keeping the water downhole.

The discovery of downhole oil, water, and gas gravity segregation in the wellbore and the ability to keep fluids separated makes it possible to generate revenue from a wellbore at the same time that it is injecting or disposing water. This paper will discuss:–Design and testing at the Rocky Mountain Oilfield Testing Center of the first Downhole Oil Water Separation (DOWS) artificial lift system to utilize downhole gravity segregation–Evolving modeling procedures–Superior environmental performance–Impediments to deploying radically new technologies–A vision of the future

P. 205
Field Trial of the First Desanding System for Downhole Oil/Water Separation in a Heavy-Oil Application
Authors: Danyluk T.L. , Chachula R.C. , Solanki S.C.
Published: December 2007

Many wells producing medium or heavy oil from unconsolidated sandstone reservoirs experience high water production while still at relatively low recoveries. Water production causes numerous operational problems leading to increased operating and capital expenditures for higher volume artificial lift systems and water handling facilities. The recent development of Downhole Oil/Water Separation (DHOWS) systems has provided operators with an alternative approach to contend with increased water production to improve recovery from these reservoirs.

PanCanadian Petroleum Ltd. has been an industry leader in the development and application of DHOWS technology, particularly with respect to its use in fields producing heavy oil. The use of DHOWS systems in such applications is complicated by the inherent production of sand with the viscous heavy oil. In the commercially available DHOWS systems, the solids that are produced tend to remain in the disposal water stream, which is reinjected downhole. Depending on the solids volume and well conditions, the solids may invade and plug the disposal zone or they may accumulate in the wellbore. In either case, these situations ultimately lead to a reduction in injectivity that reduces the effectiveness, or preclude the further use of a DHOWS system. This decline in injectivity has been observed in field trials with both progressing cavity pump (PCP) and electric submersible pump (ESP) DHOWS systems at PanCanadian's Hayter and Provost fields in northeastern Alberta, Canada (Figure 1). The accumulation of sand in the wellbore was confirmed during subsequent workovers.

PanCanadian enlisted C-FER Technologies Inc. to develop a desanding separator unit for use in conjunction with the commercially available DHOWS systems. A desanding separator unit was designed to remove solids from the produced fluids and to commingle them with the concentrate oil stream produced to surface by the DHOWS system. Following a feasibility study that examined several different design options, a prototype desanding separator was built. The functionality of the separator unit was confirmed through controlled laboratory tests and the unit was subsequently tested in combination with a PCP-DHOWS system. 'The system was then installed in a PanCanadian well which had previously experienced injectivity problems with a DHOWS system. Initial results show that sand is being produced to surface and that the injectivity has remained relatively stable.

This paper describes the prototype system developed and presents the results of the field trial conducted by PanCanadian.

P. 225
Makarem-l Relief Well Planning and Drilling
Authors: Roes V.C. , Hartmann R.A. , Wright J.W.
Published: December 2007

This case history describes planning and execution of a deep relief well operation that resulted in re-entering, killing and abandoning a wellbore which was blowing in the subsurface. In 1994, a gas exploration well, Makarem, was sidetracked past a bottomhole assembly, which had become stuck almost 1,000m off bottom. A kick was subsequently taken, indicating charging of shallower horizons from a deep, sour, high-pressure gas reservoir at potentially high rates. Attempts to reenter the original wellbore while drilling ahead in the sidetrack hole were unsuccessful. The well was re-entered in 1997 with the objective of isolating the flowing zone to prevent potential environmental impact, future drilling problems, and the loss of hydrocarbon reserves resulting from uncontrolled flow of gas in the subsurface. This case history reviews planning and execution of a deep horning-in operation to locate and re-enter the 12 1/4" open hole below the bit of the stuck assembly, 3680m below surface. Key issues addressed during the planning phase included relief well strategy, positional uncertainty, well control scenarios, options for isolation and contingencies. An active electro-magnetic ranging technique was employed to successfully locate and track the target assembly to an eventual direct intersection with the crossflowing hole. Execution of the intersection plan is detailed, with emphasis on horning-in on the fish, borehole surveying techniques and quality assurance. Also covered is the operational organisation, and details of the activities following intersection, which included stabilisation, cleanout and abandonment of almost 1,000m of borehole which had been inaccessible for over 3 years.

P. 367
Mars Debottlenecking Project
Authors: Curole M.A. , Turley A.J.
Published: December 2007

The Mars installation consists of a four (4) block unit with a Tension Leg Platform (TLP) installed in Mississippi Canyon Block 807. The discovery well was drilled in 1989. Development studies were conducted in 1990 through 1992 with project fabrication funding occurring in the fall of 1993. A twenty-four (24) well dual casing riser TLP in 2,933 feet of water was approved. The facility was originally designed to process 100,000 BBL/D of oil and 110 MMSCF/D of gas. Maximum individual well rates were estimated at 11,000 BBL/D of oil. During the fabrication phase of the project in 1995, it became clear that completion technology advances had increased the individual well production potential far beyond the 11,000 BBL/D of oil benchmark, and the ultimate TLP production potential would exceed the topsides nameplate capacity. A study was undertaken to debottleneck the topsides in order to handle unconstrained production rates. The study evaluated all phases of the production facility impacted by the increased production. This paper will present the evaluated phases of the production facility debottleneck, will sumarize the modifications to the facilities at the TLP integration site and will review the utilization of several new and innovative technologies. The facilities systems that were debottlenecked included:–Production High Rate Flowlines–Oil Treating–Compression Units–Dry Oil Sales Pumps–Utility Systems–Flare System–Gas Dehydration

P.265
Synergistic Value Optimization from Reservoir to Sales - A West Panhandle Gas Field Case History
Authors: Burgess Roy A. , Finch Clyde L.
Published: December 2007

Between 1993 and 1997, production from Conoco's West Panhandle Gas Field in Carson County, Texas was doubled from 20 to 40 MMCFPD. By 1993, reservoir pressure had fallen below 30 psig and production from the wells was at an all time low. The wells, many of which were drilled during the first half of the century, were showing signs of age and poor mechanical condition. In 1993, Conoco gained operational control of the gas gathering system and conducted a multi-well pilot that increased production from 300 to 1,250 MCFPD in a few months. The subsequent full-scale optimization of the 100,000 acre field involved working-over more than 100 wells, drilling replacement wells, installing electric vacuum compression on nearly 100 wells, erecting over 90 miles of high voltage power line, adding 6,400 HP total at five compressor stations and debottlenecking the gas gathering lines.

P. 303
A Method for Delumping the Results of a Compositional Reservoir Simulation
Authors: Leibovici Claude F. , Barker John W. , Wache David
Published: December 2007

A new method for delumping the results of a compositional reservoir simulation is presented. The method is based on a previously published algorithm for delumping the results of a single flash calculation. Results are presented for two cases: depletion of a volatile oil reservoir and depletion with lean gas reinjection. The compositions obtained by delumping the results of a 7-component reservoir simulation are compared with those obtained from a 16-component reservoir simulation. If there are no binary interaction coefficients, the agreement is almost exact, and the delumping takes only a fraction of the computation time of the 16-component simulation. When non-zero binary interaction coefficients are introduced, the accuracy of the method is slightly reduced. P. 339
Upscaling, Gridding, and Simulation Using Streamtubes
Authors: Portella Ricardo C.M. , Hewett Thomas A.
Published: December 2007

This paper presents an innovative upscaling methodology based on the semi-analytical simulator developed in the first part. The methodology generates a coarse grid based on streamtubes and isobars, whose upscaled properties are accurately calculated using the properties of each streamtube that constitutes the coarse block. Beyond the calculation of upscaled static properties of the grid, the methodology also calculates upscaled relative permeability curves, or pseudoflinctions, using the semi-analytical streamtube method to perform this without requiring any significant additional time. Tests showed that the results from the streamtube coarse grid had an excellent agreement with the fine grid solution. In contrast, simulations with a coarse grid upscaled with conventional techniques failed in many situations. Although this upscaling methodology is heavily based on a fixed streamtube simulaflon method, it provided good results even for situations in which this streamtube simulator is not supposed to work, such as displacements with favorable mobility ratios, and for problems with gravity and compressibility.

P. 361
Field Measurements of the Effects of Drillstring Velocity, Pump Speed, and Lost Circulation Material on Downhole Pressures
Authors: Clark R.K. , Fontenot J.E.
Published: December 2007

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

Detailed downhole pressure measurements were made in two wells to observe the effects of pipe velocity and circulating rate in weighted pipe velocity and circulating rate in weighted oil-base and water-base muds. The effects of lost circulation material on downhole pressures in the water-base mud were also measured. A major conclusion is that control of the instantaneous (rather than the average) pipe velocity while tripping and making connections is necessary to minimize pressure changes downhole.

Introduction

The control of downhole pressures while drilling is an essential part of well control. Changes in downhole pressure result from drill string movement, pump operation, and changes in mud rheology and density. The addition of certain types of lost circulation material to control mud losses can increase mud viscosity and downhole pressures and therefore can aggravate the lost circulation problem. Knowledge of the downhole pressure at all times is of great importance to the success of any drilling program.

In view of a lack of published data on downhole pressures in various phases of drilling operations, a program was initiated to measure downhole pressures as they are affected by circulation rate, pipe velocity, and the addition of lost circulation material. Detailed pressure measurements were made in two wells, pressure measurements were made in two wells, one in a weighted oil mud and one in a weighted water-base mud. The effect of lost circulation material was determined in the test with a water-base mud. This paper discusses the pressure data obtained and the conclusions pressure data obtained and the conclusions derived from the data.

Background

The importance in well control of downhole pressure changes caused by circulating the mud and moving the drill string has been recognized for some time. In 1934, Cannon measured swab pressures due to drill string movement, and in 1951, Goins reported measurements of surge pressures resulting from drill string movement. Graphic descriptions of these pressures were given by Cardwell and Clark. The last reported measurements of downhole pressure changes were those by Wilson in 1962. Burkhardt and Schuh have described analytical methods of calculating downhole pressure changes. The authors have recently pressure changes. The authors have recently described a new computer program for calculating swab/surge and circulating pressures.

The previous measurements of downhole pressure changes have been very limited in scope pressure changes have been very limited in scope and in instrumentation.
Extra Increments of Pressure or Mud Weight Safety Factors Added During Well Killing Procedures Can Be Unsafe
Authors: Kastor R.L. , Letbetter S.C.
Published: December 2007

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

Introduction

It is common practice during drilling of a well to carry an overbalance or increment of md hydrostatic pressure greater than the anticipated formation pressure at any point in the hole to maintain primary control of the well. In addition, during the drilling operation this overbalance usually allows manipulation of the drillpipe without swabbing formation fluid into the hole, unless drillpipe motion is excessive. Common overbalance margins range from 300 to 500 psi, although in some areas wells have successfully been drilled with an underbalance. The commonly held concept is that an increment of hydrostatic pressure over the formation fluid pressure provides the safety factor that allows effective control over the well.

During well-killing procedures, however, these extra increments of pressure from mud weight may cause problems in well control. They may require the holding of extra backpressure on the casing annulus in order to maintain a constant bottom-hole pressure. As a result, in a well having a marginal fracture of breakdown pressure, it is possible that this extra pressure, it is possible that this extra pressure may result in fracturing the formation, pressure may result in fracturing the formation, which could ultimately result in losing control of the well.

It is believed this phenomenon could best be explained by the use of a series of examples that follow.

BASIC KILL PROCEDURE

At the present time, a great many operators agree that the safest well control procedure is the constant bottom-hole pressure method, which in turn infers maintaining a constant pump speed and, for the largest part of the kill procedure, maintaining a constant drillpipe pressure. Therefore, it will be assumed that the standard constant bottom-hole pressure technique is being utilized, and the examples will relate to this concept. Later, variations will be considered and discussed.

There are two basic methods for applying the constant bottom-hole pressure method of well control. The first of these, known as the "driller's" method involves first circulating out the well kick with the same mud weight used in drilling the well, and maintaining secondary control of the well by holding an annular backpressure. Subsequently, after the gas kick has been circulated from the well, the drilling mud is replaced with a higher mud weight sufficient to return to primary control of the well.
Recovery Optimization Through Infill Drilling Concepts, Analysis, and Field Results
Authors: Driscoll Vance J.
Published: December 2007

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

This paper gives theoretical concepts and some supporting mathematical model and field performance data which demonstrate factors t at performance data which demonstrate factors t at can be involved in recovery increases by drilling. Many of these factors relate to various reservoir heterogeneities and are quantitatively more important in fluid injection projects. Recovery increase by infill drilling projects. Recovery increase by infill drilling of low-permeability waterflood projects can be due to as many as nine different factors with varying degrees of technical difficulty to specifically quantitize. However, based on performance and certain theoretical knowledge performance and certain theoretical knowledge and concepts, reasonable factors involving judgment can be developed as to percent of original oil-in-place recovery increase.

Attractive conventional growth economics based on increased ultimate waterflood recovery are indicated for areas of low-permeability, slowly depleting reservoirs with relatively large amounts of oil in place. This is in addition to substantial increases in current rates of production and present worth. Typically, an increase on the order of 4 percent of the original oil in place will be percent of the original oil in place will be gained by infill drilling from 40- to 20-acre spacing. However, this can vary by a factor of two or more depending upon the specific situation.

Introduction

There is probably no place more than reservoir engineering where a spirit of Hegelian dialecticism applies. That is, there is "truth" and "error." However, in the truth there still exists some error. Consequently, with time a new truth evolves that is purged of some previous imperfections. In the 1940's, Uren, previous imperfections. In the 1940's, Uren, Muskat, and predecessor companies of Exxon, among others, published thinking and results properly decrying misapplications of Cutler's properly decrying misapplications of Cutler's rule. This had been a previous empirical observation which indicated that primary recovery in densely drilled portions of fields was greater and proportional to the square root of well density. It was generally shown that this was due to migration from less densely drilled areas of the same fields rather than an increase in over-all recovery.

The tendency since about the 1950's has been to consider increased recovery by infill drilling as negligible or only to consider it where some one factor in a particular reservoir had a dramatic effect upon recovery. This has been partly due to past limitations on ability to realistically describe and simulate actual reservoir heterogeneity and displacement.
A Comparison of Actual vs Calculated Ground Level SO2 Concentrations During Field Flaring of Sour Gas
Authors: Stan P.W. , Bossert D.W.
Published: December 2007

Due to the tightening of air pollution control regulations, all sour gas flaring operations, such as used on well cleanups after performing workovers, have to be performed in a manner which will not yield performed in a manner which will not yield SO2 ground level concentrations in excess of the regulations, as calculated by the Pasquill equation. Amoco personnel using meteorological data, land terrain, and the Pasquill method of calculation, set up mobile monitoring equipment to measure and, therefore, control flaring operations to ambient air standards. This provided the opportunity to obtain a comparison of actual ground level concentrations to Pasquill calculated concentrations. The data indicates that downwind ground level concentrations can better be determined by measurement with mobile monitoring units than by theoretical predictions.

Introduction

Flaring of sour gas wells in the Crossfield D-1 Unit located 30 miles north of Calgary is required to recover workover fluids and enable the wells to produce against the gathering system back pressure. Government regulations require that the flaring of sour gas shall not result in exceeding the maximum half-hour ground level SO2 concentration of 0.20 ppm for populated areas. Five large volume acid frac workovers were performed during 1973–1974 and these wells had to be flared within ambient air standards set by the government at levels calculated by the Pasquill equation.

A computer program utilizing the Pasquill method of calculation was used to determine a wind restriction above which flaring operations would be discontinued or new stack dimensions proposed so that the maximum allowable SO2 concentration is not exceeded for the most disadvantageous weather conditions and maximum flaring rate expected. The maximum wind speed allowed by the Pasquill calculation for the existing stack (75 ft. × 6 inches) was calculated to be 10 mph. The highest commercially available portable flare stack is 160 ft. × 8 inches which would impose a 15–20 mph wind speed limitation by calculation. Both these alternatives were impractical for the Crossfield Area where wind speeds may average 20–25 mph. Discontinuing of flaring operations due to a wind speed limitation during the initial flaring operations may result in the wellbore loading up with fluid.
Blackback Field Development - An Example of Technical and Commercial Risk Mitigation in a Deepwater Marginal Field
Authors: Perrett T.L. , Garven I.M.
Published: December 2007

The Blackback structure is a large, top-Latrobe, eroded and faulted anticline within the Gippsland Basin of south east Australia. Despite its large areal extent, it is a commercially marginal field due to reserves uncertainty, deep water and the practical difficulties of development. Proximity to existing infrastructure helps to make this marginal field commercial.

Five wells have been drilled on the Blackback feature, and have intersected reservoirs with greatly varied geological and geophysical properties. The resulting uncertainty over the ultimate recovery remains, despite the five wells drilled to date. This paper describes the geological and development risk mitigation undertaken by a non-operating Joint Venturer to reduce the technical and commercial uncertainty pertaining to a second phase of development. This includes the development of a predictive depositional model targeted at the upside potential and maximum use of existing infrastructure.

P. 209
Money for Energy: The Role of International Banks
Authors: Yurchyshyn George B.
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 financing of large energy projects is a well developed area of lending in the United States. Over the past thirty or forty years billions of dollars have been lent by the public market, by insurance companies, and public market, by insurance companies, and by banks to finance the impressive grid of pipeline that overlays the U.S. New pipeline that overlays the U.S. New petrochemical plants, refineries, and nuclear petrochemical plants, refineries, and nuclear power plants have had few financing problems, power plants have had few financing problems, at least until environmental concerns and governmental economic restraints made further investment in these areas more risky.

Most bankers are confident about the availability of sufficient money to finance the large energy projects proposed for various sections of the U.S. and for adjacent coastal waters. The U.S. possesses the world's largest capital market whose main strengths lie not only in the dollar amounts that may be raised but also in the different kinds of lenders who are able to offer funds on different terms, giving projects a certain flexibility in matching their particular borrowing needs with an appropriate lender. Periods of economic uncertainty such as we Periods of economic uncertainty such as we are seeing in 1974 may make some types of financing unattractive, but financing is generally available. On the international side the picture is not as bright and significant problems can be anticipated. outside the U.S. we presently see three broad funding sources:Domestic capital markets in foreigncountries.Export financing schemes of individualcapital equipment producing countries.International capital market.(A) Eurocurrency loans(B) Eurobonds

Let us briefly look at each of these potential funding sources. potential funding sources.(1) Domestic Capital Markets:No foreign capital market approaches the size of the U.S. market. Even collectively, the capital markets of all the West European countries equal only a fraction of the U.S. capital market. It is rare in West European markets to see stock or bond issues in excess of $100 million. Foreigners borrowing in European money markets are even more restricted. Switzerland, the fabled land of untold wealth, rations access to its capital market very carefully, and few foreign borrowers have ever floated a bond issue in excess of the S.Fr. equivalent of U.S. $30million. Although steps are being taken in individual countries to make their capital markets more attractive to investors, these are long-term plans and goals from which today's projects will not benefit.
Long-Term Effects Of High Temperature On Strength Retrogression Of Cements
Authors: Eilers L.H. , Root R.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.

Neat Portland cement systems lose strength and become permeable at temperatures above 250 degrees F. This deterioration usually is more extreme over the first few days or month of heating but is usually not severe enough to cause disintegration of the neat cement. After this initial regression many neat Portland systems will regain a portion of Portland systems will regain a portion of their strength and reduce in permeability. This temperature regression of cement can largely be prevented by using about 35 per cent very fine silica sand. The strength can be maintained or increased but permeability will increase. Most additives for oil well cements can be included in such a silica stabilized system without extensive effect due to temperatures up to 600 degrees F. An exception to this is fly ashes and, to some degree, natural pozzolans. These are stable at 450 degrees but are losing strength and recrystalizing 600 degrees F.

Introduction

The deterioration of Neat Portland cement at temperatures above 250 degrees F (120 degrees C) has been known for many years. Menzel proved that fine silica added to a Portland cement paste would improve the strength of cements cured at elevated temperatures.

An increasing number of wells are being subjected to these elevated temperatures each year. Deeper and hotter oil and gas wells are being drilled and other wells are being subjected to hot water, steam, or fire flood methods. High temperature geothermal wells are also increasing in number each year. The cement in these wells will be subjected to elevated temperatures from bottom to top. It is probable, therefore, that the surface and intermediate strings on many of these wells are not adequately protected from deterioration.
Sand Consolidation Systems Placed with Water
Authors: Murphey J.R. , Bila V.J. , Totty K.
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.

Sand consolidation systems using resinous materials have been developed which require only water (brines) in the placement procedures The use of water treating fluids is solving several important problems in the field associated with current consolidation methods which use oil placement fluids.

The brine treating fluids are easily handled and have presented no disposal problems, particularly on offshore locations. The desirable particularly on offshore locations. The desirable weighting and no fire hazard characteristics of brines have improved safety. These aqueous fluids can be used in gas and non-potable water (source or injection) wells where it is undesirable to use oils. Waters to prepare the brine treating solutions are readily available. Formation brine, fresh water, bay and sea waters have all been used. The ready availability of these fluids has resulted in reduced "storage tank" requirements on water job sites and have eliminated transport needs required in getting treating oils to offshore facilities. Considerable volume of oil is being saved on each application by using brines.

The paper describes two separate consolidation procedures. One involves the consolidation procedures. One involves the consolidation of formation sands with neat resins using brine placement fluids and the second describes the placement fluids and the second describes the packing of formations with resin-coated sand packing of formations with resin-coated sand placed in a water carrier. With both systems placed in a water carrier. With both systems an aqueous hydrochloric acid solution is used to overflush catalyze the placed resin resulting in consolidation of the sands. Deemulsifier surfactants may be used in all treating solutions including the organic resin.

The first technique, involving the placing of neat resin, has been successfully applied in a bull-head squeeze procedure requiring no or minimal rig facilities on location.

Laboratory results and field development data on fourteen initial applications are presented. presented

Introduction

The petroleum industry's sand problems are both widespread geographically and persistent historically. Sand control has persistent historically. Sand control has consequently meant a succession of solutions.
Evaluation Of The Alberta Tar Sands
Authors: Sah R.C. , Chase A.E. , Wells L.E.
Published: December 2007

Introduction

There are three major tar-sand areas in Alberta: the Alberta Tar Sands, the Cold Lake Tar Sands, and the Peace River Tar Sands. The total reserves in place are estimated at 1,000 billion barrels, and recoverable reserves are estimated at 400 billion barrels.

The Alberta Tar Sand area is the largest of the three. It covers 5.75 million acres. As shown in Fig. 1, it is located in the northeast part of Alberta, between Township lines 77 and 103 and between Range lines 6 and 20, west of the Fourth Meridian. The estimated reserves in place, in terms of the depths from which they have to be recovered, are tabulated below: Reserves Depth (billions of barrels) 0 to 100 ft 45.1100 to 1,000 ft 373.9Deeper than 1,000 ft 207.0 Total Resreves in Place 626.0

The Tar Sands belong to the early Cretaceous. Fig. 2 shows the simplified geological cross section' along the dashed line in Fig. 1 from A to B. As the Elk Point salt (fine cross-hatch on Fig. 2) collapsed, the overlying Beaverhill Lake limestone formed a basin for Cretaceous sediments. The overlying tar sands (in black) are unconformable to the limestone. The tar-sand sediments are deposited in predeltaic, deltaic, and post-deltaic environments, Pre-deltaic and deltaic sediments are rich in tar, and their matrix materials contain 90 to 95 percent by weight of quartz.

The post-deltaic deposits are poor in tar and their matrix materials contain only 50-percent quartz by weight.

The tar differs from conventional oils. It has low gravity (6 degrees API at 60 degrees F), high viscosity (3,000 to 300,000 poise at 60 degrees F), and is undersaturated in hydrogen.

The bituminous tar sand will be mined and physically removed to an extraction plant. There, it will be processed and upgraded to produce "synthetic" crude. This mining and processing operation involves a large capital investment in the plant and equipment. Also considerable are the daily costs of mining and transporting large quantities of tar-sand ore. It is important, therefore, to have an accurate evaluation of the tar-sand deposit before so great an investment is committed. This requires a large number of test holes from which the needed information can be derived.

An evaluation system involving the analysis of a suite of well logs from each test hole can be used to appraise these ore bodies. Such analyses of the large volumes of data available from logging programs in many test holes are best handled by computer. Also, use of the computer makes possible an evaluation system which has a high capability possible an evaluation system which has a high capability for producing all of the desired answers. Furthermore, machine computation of well logs is fast and minimizes the problems associated with laborious intensive-evaluation problems associated with laborious intensive-evaluation systems done manually.
The Use of Centrifugal Separators for Offshore Gas Production
Authors: Lobdell W.R. , Ayers L.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.

Introduction

The use of centrifugal force to separate fluids is a proved process that has been applied by many industries. The force is explained in college physics textbooks under uniform circular motion where Newton's laws of motion are discussed. A classic textbook example describes an object of known weight that is held in a circular path by a string of known length, and the weight is moving at a constant speed. The inward force that is developed is known as the centripetal force. The equal and opposite reaction that is in the outward direction is known as the centrifugal force. This is the force that we use to separate gas well fluids in a centrifugal-type separator.

The flowing pressure at the wellhead furnishes the energy for the process. Upon expansion to a lower pressure at the wellhead choke, the natural gas, condensate, and water flow to the centrifugal separator for rotation and subsequent separation. The fluids tend to separate in layers of uniform density. Water collects on the internal surface of the separator, condensate flows on the water, and the gas flows in a circular pattern in the center of the vessel.

FUNDAMENTALS

The following formula for centripetal - force summarizes the process.

2WVFc = ———,gR

where Fc = centripetal force, lbW = weight of the fluids, lbV = velocity, ft/secg = gravity constant, 32 ft/sec/secR = radius of the circle, ft

The centripetal force, Fc, is that force in the inward direction, expressed in pounds, that is developed when the fluids are directed in a circular path in the separator. The centrifugal force is an equal and opposite reaction to the centripetal force; therefore, calculated values for Fc are vend for the centrifugal forces in the outward direction.

The weight of the fluids can be calculated from the fixed dimensions of the internals of the vessel, the operating pressure, and temperature in the separator, and the gas-condensate ratio and gas-water ratio of the flowing stream.