bluuebunny/crossref_metadata_2025 huggingface dataset:
Frac Packing Offers Development Advantages for Ewan Field in Nigeria
Authors: Onasanya A. , Tibbies R. J. , Moran J. H. , DeBruin R. J.
Published: December 2007

Prior to 1995, sand production from the non-gravel packed wells and low productivity from a gravel packed well were factors which impacted the potential development of the Ewan Field, offshore Nigeria. To make the field a more attractive development candidate, horizontal and frac-pack completions were recommended. This paper compares the results of the first frac-packed well, which was expected to improve both production rates and ultimate recovery, with the previous gravel pack completion. Pressure build-up and production data show the improved productivity obtained after frac-packing. The results from the first frac-pack were so encouraging that field development includes frac-pack completions for all non-horizontal wells.
The Effect of Surface and Interfacial Tensions on the Recovery of Oil by Waterflooding
Authors: Kennedy Harvey T. , Guerrero Erasmo T.
Published: December 2007

In this investigation, the effects of the surface tension of brine and the interfacial tension between oil and brine on the recovery of oil by waterflooding of Woodbine sand was studied. Variation of the surface forces was obtained by the addition of small amounts of commercially available chemicals, which did not appreciably change the surface tension of the oil.

Fourteen surface-active agents, which were found to be effective in lowering the surface and interfacial tensions were further investigated to determine the extent of their adsorption by the Woodbine sand cores. It was found that adsorption was sufficient in all cases to prevent any substantial concentration of chemical at the flood front. The flow system was, therefore, brought to equilibrium with definite concentrations in the flood water by circulation before each test. The data thus have no relation to the results obtainable by using the chemicals in full-scale waterfloods, but should be helpful in predicting the performance of surface-active chemicals which are not lost by adsorption, such can be found.

Flow tests were made on various concentrations of six chemicals selected from the fourteen investigated for surface activity and adsorption, with and without the presence of gas in the core.
What Price Deliverability?
Authors: Hanna L.E.
Published: December 2007

One of the public questions of major concern confronting our nation today is the sufficiency of our energy supply. In recent months we have seen voltage reduction and partial blackouts of electric service in partial blackouts of electric service in several parts of the country; the development of tight supplies of coal and residual fuel oil, and, of course, the subject of which we are so intimately aware: the decline in new discoveries of natural gas. While it is not my purpose today to launch into the reasons and possible solutions, it is important to keep the entire national picture in focus as we look at one aspect of picture in focus as we look at one aspect of gas supply.

We all know that reserves don't have much meaning until they are translated into flowing gas. Deliverability on a daily basis is the key to our ability in the transmission business to meet our customer's needs. Our mission today is to examine what has been happening in two of the oldest and, at one time, most prolific sources of flowing gas; namely, the Hugoton and West Panhandle Fields. From time to time I shall make specific references to our own experience, although the conditions now apparent affect all pipeline buyers in these two fields.

Although gas had been discovered some years before, production in large volumes began in the Hugoton and West Panhandle Fields in the late twenties and Panhandle Fields in the late twenties and early thirties. Initial pressure was about 450 psig in both fields.

Panhandle Eastern and the other companies began tying in wells and building gathering systems as the needs of each company developed.
Defining Oil And Water Entries In Producing Wells
Authors: Schaller Herman E.
Published: December 2007

"Production Logging" is gaining ever increasing importance as the petroleum industry continues its efforts to increase the badly needed recovery of known reserves.

To provide the optimum assisted recovery system for a reservoir it is highly desirable to know the dynamic flow characteristics of the reservoir, both for the injection wells and the producing wells. This information is also important during the producing life of a reservoir to not only provide routine producing life of a reservoir to not only provide routine monitoring data, but also when problems arise to furnish a factual basis on which to evaluate and hopefully correct such problems. This paper deals with the dynamic conditions existing in producing oil wells and the parameters involved. It describes the approach used in defining the intervals contributing oil and/or water and the quantities of each. Actual examples of surveys are presented, with reference to the use of this information where available.

Introduction

Subsurface analysis of fluid flow in producing oil wells is quite complex when compared to similar types of measurements in injection wells. Under injecting conditions, generally only one phase is present, usually water but also possibly hydrocarbons phase is present, usually water but also possibly hydrocarbons either in liquid or gaseous form. Under single-phase conditions it is relatively straightforward to measure the rate of fluid travel at any given depth, either by the use of an appropriate radioactive tracer or an electromechanical device such as the continuous spinner or packer flowmeter.

PRODUCING WELL FLOW CONDITIONS In dealing with producing wells (under normal producing conditions), generally two phases (water and oil) are present; and in addition, free gas may also exist in the wellbore. Assume a system where the flow stream is 4-in. diameter or larger and rates where the water may range up to 2000 BPD and oil to 500 BPD. Under these conditions and in oil cut not to exceed 50 per cent of the gross fluid, flow conditions will probably be that of two distinct and separate fluids (water and oil), each having its own flow characteristics. Water, being the heavier fluid, will be present as the continuous phase from the intake of the flow string present as the continuous phase from the intake of the flow string to the effective depth of the well, and any oil present will be as the dispersed phase. (It is likely that this condition will prevail where any substantial amount of water is being produced.)
Packer Snubbing Program Protects Elk Hills Wells Turnkey Contract Reduces Costs
Authors: Young S.A. , Burch W.H. , Muse J.F.
Published: December 2007

The Elk Hills Naval Petroleum Reserve No. 1 in the San Joaquin Valley of California, which was set aside in 1912 and developed in the mid 40's and early 50's through acts of Congress and employing the resources of the Standard Oil Company of California as operator, was completed within the technology of the period. The majority of the wells in the Stevens Zone which range in depth from 5,000 ft. to 7,400 ft. with bottom hole pressures of 3,000 psi, were completed without packers but with tubing in the hole.

As a result of a growing concern for the protection of this untouched prolific oil reserve and for more efficient operation should the need arise to produce the field, it was decided to install packers and sub-surface check valves in wells from the Stevens Zone. All operations were conducted by a supply-service company on a lump sum turnkey contract for the operator.

In order to minimize formation damage and because the economics were favorable and to preserve productivity, it was decided to snub out the tubing as opposed to killing the wells. Because of wellhead configurations, only 193 wells lent themselves to the snubbing operation, leaving 25 remaining wells to be killed. Conclusions:

- snubbing, although generally regarded as a last resort because of its presumed higher cost, not only proved to be less expensive than killing operations but considerably more desirable from a well productivity standpoint.

- Turnkey operations provided by a reliable service company on contract may permit substantial reduction in overall cost.

Introduction

The United States Naval Reserve No. 1 (Elk Hills) (Fig. 1) with an area of 38,072 acres and located in Kern County, California was set aside by an Executive Order issued by President Taft on September 2, 1912. This action was taken in response to a request from the Secretary of the Navy in cooperation with the Secretary of the Interior to secure the reservation for the Navy of oil bearing land in California sufficient to insure a supply of 500 million barrels of oil. There was appreciable acreage in the Reserve originally patented to the Southern Pacific Railroad title of which was subsequently passed to the Pacific Oil Company and later to Standard Oil Company of California.1,2
A New Concept in Pumping Unit Technology
Authors: Metters E.W.
Published: December 2007

A number of years ago, my company realized that existing equipment considered adequate for producing oil wells at the time would not be capable of producing wells of the future. All forecasts indicated there would be a need for equipment to produce from deeper wells and produce higher volumes from the more shallow wells.

A research and development project was initiated with the assignment of determining the most efficient means of lifting fluid from the producing zone to the stock tanks. All known producing zone to the stock tanks. All known methods of lift were investigated. The results of the investigation showed each system under a certain set of conditions could be classified as the most economical, but not necessarily the most efficient. The department finally philosophized that the most efficient means philosophized that the most efficient means would eventually develop into the most economical.

One system stood out above all others in its ability to lift fluid with the least lost effort. This, as you would suspect, was the conventional sucker-rod lift system. Further study showed that, even though the sucker-rod system over-all was the most efficient, as the loads increased either by volumes lifted or by increase in depth or a combination of the two, the efficiency of the system became much less and the projected cost of operation became too expensive to be commercially feasible.

With volumes of data on hand regarding attempted production of heavy loads utilizing sucker rods, there was one method which was able to produce fluid with a much reduced down-hole cost and a comparative good down-hole efficiency. This was the long-stroke hydraulic pumping unit.

The use of hydraulic pumping units reached its peak during the early 1950's. Without a doubt the manufacturers and the operators did everything possible to make the hydraulic unit operational, but it was a very complex piece of equipment and, except for an isolated instance or two, all the thousands of units had to be retired. The cost of maintenance was too high and the reliability far too low to be considered as acceptable.

Much was learned during this period. Due to the long stroke, at a constant velocity more fluid could be produced with far fewer cycles; hence, much more fluid could be produced by the sucker rods during their life expectancy. Subsurface pump problems were dramatically decreased. This is easily understood when you consider the barrel wear is distributed over a much greater area, and the velocity of the fluid through the valves is much lower than would be encountered with conventional surface equipment.

The research and development department then concentrated its efforts on a machine that could generate a long-stroke alternative to a beam type, which is relatively efficient at lifting lighter loads but becomes progressively less efficient as the loads increase.
Planning For and Managing Industrial Environmental Problems at the Corporate Level
Authors: Lent Robert R.
Published: December 2007

The many problems related to industrial environmental pollution are identified and discussed. People, technology, earnings, capital requirements, legislation, politics, and planning are complicating elements of the total problem.

I wondered and pondered a long time, trying to come up with a good way to begin a discussion of this type.

Then I remembered from my school days that fables are an effective way to make a point and, through the moral, to emblazon it point and, through the moral, to emblazon it on the hearer's mind.

So let me start out with a fable. Let's see how well I can compete with Aesop. I'll call it a Fable for Our Time.

Once upon a time — all fables begin that way, don't they? — there was a small city in a remote area. It had no traffic problems because it had no traffic to speak of. The city was very isolated — from the world, even from the twentieth century.

When the automobile finally was introduced there, it presented no problems at first. Few people had a car, and those who had one didn't drive very much. Traffic laws, then, were unneeded and non-existent.

But over the years the city grew and grew, and the number of automobile owners grew and grew. And they drove more and more.

And what havoc that growth did reap!

The rush hour became utter chaos. Collisions were many and often. People were killed and maimed. Irritation and frustration abounded, to the tune of great cacophonies of honking horns and bending fenders. Something clearly had to be done.

The situation, of course, was very emotional. Politicians propounded and expounded, in search of a headline. Students demonstrated. Mothers marched. Militants bombed. Letters to the editor were many and bitter. Gloom descended. An untimely end for the human species was regularly predicted.

The government reacted.
Safety Equipment That Can Help Prevent Pollution
Authors: Wilder Odis
Published: December 2007

Due to recent happenings that have received wide publicity the oil industry is, out of necessity, becoming keenly aware of the need to look very closely at safety systems and equipment to meet requirements of regulatory agencies and, at the same time, provide the best possible protection for their wells.

This paper presents some of the equipment that is available to the industry. It deals with subsurface equipment and design as well as surface equipment and design. Operation of the equipment, in most cases, is explained in detail.

Introduction

Pollution has been a problem in the oil industry, almost from its beginning. There are numerous types of pollution that can be directly and indirectly tied to the oil industry, but it is our purpose in this discussion to deal primarily with prevention of pollution from the standpoint of oil spill, whether it be on offshore platforms land locations, or drilling locations.

When looking at this problem objectively, we know why there are oil spills. With this in mind, we proceed to find a solution. Often times these problems seem difficult to solve, but with advanced technology and engineering ability that is available to the oil industry today it is reasonable to assume that the answer will be found. In reality, the solution is fairly simple. It is a matter of knowing what is required, selecting the necessary equipment to do the job, using the proper design, enacting a strict safety maintenance program and make it work. You, the producer, program and make it work. You, the producer, have an investment to protect.

Downhole Design

Perhaps the most important phase of any oil or gas well is during the completion stage. It is at this point that a "Life of the Well Concept" should be considered. Considerable money has already been spent to drill and case the well. The downhole equipment required to complete the well is, in most cases, a small percentage of the costs to this stage.
Sub-Surface Disposal of Acidic Effluents
Authors: Ostroot G. Warren , Donaldson Arthur L.
Published: December 2007

A study has been made as to the effect of acidic type effluents for Deep Well disposal, on various cementing compositions as well as their effect on plastic pipe. Data will include laboratory test results on API Class A, C and H Cements, Pozzolan Cement, Resin Cement, Gypsum Cement with Resin Phase and a Resin Slurry using Sulfuric Acid, Nitric Acid, Hydrochloric Acid and Mixed Acids. A section is devoted to well design which includes optimum pipe to hole size ratios, recommendations for down hole equipment such as special packers, the use of plastic and stainless steel pipe and various techniques gained from field experience in cementing Acid Disposal Wells.

Introduction

It is only within the last decade that the magnitude of the damage wrought to our natural resources, surface as well as sub-surface, has become a major concern to individuals, sportsman groups, conservation, State and Federal Government Agencies. Viewpoints are many and varied as to the availability of sufficient fresh water supplies to take care of both human and industrial needs, however, the consensuses seem to be that supplies are available if they are not wasted through misuse or by pollution from industrial wastes. More stringent laws are in the making by both the State Governments and the Federal Government.

Most areas are concerned with the problem of pollution in one form or another, with the more serious situations developing in industrialized and metropolitan areas. In many of these areas, water pollution as pertains to lakes, rivers and streams as well as underground fresh water supplies is a very serious problem.

The primary methods used in the disposal of industrial wastes are surface and sub-surface. Many different means have been used in surface disposal operations depending upon the type of waste and the condition of the final waste at the receiving point. Generally the treatment for surface disposal is classified as chemical, physical, or biological; however, any physical, or biological; however, any combination of these three may be used. Where the final product is deposited back to an area for re-use, some of the more expensive methods of surface disposal include land fills, settling tanks, filtration systems, aeration, floatation, oxidation, chlorination, pH adjustment, etc. These are not the most effective methods of waste disposal as considerable damage can result from spillage, overflow from heavy rains, seepage, etc.
Environmental Protection At The Line Level
Authors: Honeycutt Baxter D.
Published: December 2007

Line level environmental programs are presented. These include regulated presented. These include regulated investment protection measures which also protect the environment, preparation of oil spill contingency plans and ecological programs. Cooperative ecological research can be initiated between producing districts and governmental agencies and universities. That base line ecological surveys are necessary for emergency planning and to measure industry and resort impact on marine areas near shorelines is emphasized. Specific measures that line level personnel can institute for environmental protection are outlined.

Introduction

Growing concern with the state of our environment has made mandatory inclusion of ecological protective measures into the first level supervision of oil and gas drilling and production. The highly publicized Torrey production. The highly publicized Torrey Canyon, Santa Barbara Channel and Main Pass Block 41 oil spills focused much criticism on offshore operations. As a result, naturalists, fishing interests, government agencies, and conservation groups such as the Sierra Club are closely examining our operations in coastal waters. A valid concern of theirs is that the bays and estuaries must be protected as they are the nurseries for the abundant marine life in the seas.

Regulated Protection Measures

A line supervisor answers this need for protection of the invaluable marine life protection of the invaluable marine life while serving to provide minerals which are also necessary to our society. This supervisor is the man responsible for coordinating activities between various operating sections such as drilling, producing and engineering. First he takes measures as a prudent operator to protect his investment, consequently protecting the environment. Examples of these protecting the environment. Examples of these are (1) engineered well drilling programs, (2) adequate blowout prevention equipment, (3) tubing flow controls, (4) vessel sizing, rating and venting, (5) high-low liquid and pressure controls, (6) flame and gas detectors, (7) sprinkler systems, and (8) corrosion preventive measures. Rules of State and Federal preventive measures. Rules of State and Federal regulatory agencies spell out these measures and they are strictly enforced, but the real responsibility lies with the supervisor.
Some Aspects of Simultaneous Horizontal Two-Phase Fluid Flow Through Pipelines
Authors: Schneider Frederick N. , White Philip D. , Huntington R.L.
Published: December 2007

Introduction

During the past decade a number of pipelines have been laid through which oil and gas are flowed simultaneously. In certain areas such as swamps and offshore locations, this method of transportation has been favored. Whether the advantages gained from separate lines offset the additional cost of those as compared to a single line carrying both is still a moot question.

Another problem which is encountered in two-phase flow is the feasibility of injecting a liquid drying agent, such as diethylene glycol, into natural gas lines in an effort to reduce hydrate formation. In pipeline design the prediction of the increase in energy loss and liquid holdup are questions which plague the engineer and will remain unanswered until the mechanism of two-phase flow is better understood.

It is essential that lines carrying two phases be of sufficient diameter so that the pressure drops will not be too high and yet their size will be small enough so that the cost will not be excessive. It is well known that the energy losses experienced in two-phase flow are ordinarily higher than those for single-phase flow. This is due not only to the irreversible work done by the gas on the liquid as it is dragged along but also to the reduced flow areas resulting from the presence of two fluids. No completely satisfactory means has yet been found to calculate the pressure drop resulting under a given set of conditions. Also, the dependence of the various flow types upon flow rates and other physical properties is not well understood. As two-phase flow now is being used to a greater extent in industry, the need for additional experimental information has increased. It was with this thought in mind that the present investigation was undertaken.

Some of the early experimental work was reported in 1939 by Boelter and Kepner. They studied two-phase flow occurring in a fuel distributing system for heaters in California orchards, and their data cover flow in 1/2 and 3/4 inch metal pipe of 50 ft lengths. Although they presented no correlation, it was suggested that the pressure gradients were functions of various dimensionless groups.

In 1944 the first general correlation was developed by Martinelli, Boelter, Taylor, Thomson and Morrin. A further analysis was made by Martinelli and co-workers covering the viscous region in 1946. Their tests were made in tubes of two to 50 feet in length ranging in size from capillary tubing to one inch pipe.
Fatigue Of Threaded Sucker-Rod Couplings
Authors: Bellow D.G. , Faulkner M.G.
Published: December 2007

Accelerated laboratory tests on the fatigue characteristics of sucker-rod couplings were carried out on a closed-loop hydraulic testing system. The purpose was to evaluate a number of different thread designs currently being used in the manufacture of sucker-rod couplings. The thread forms tested included the simple cut, a keyhole, cut and burnished, cut and cold worked and fully cold worked.

The results show that the fatigue life increases as the degree of cold-working increases. It is also seen that the effects of accelerating the testing are insignificant.

Introduction

The failure of sucker-rod joints is of considerable interest to those involved in petroleum production. To eliminate or minimize such failures many attempts have been made both, to producing new rod and coupling designs, and to eliminating the coupling altogether. The literature shows a number of papers dealing with the subject of joint failures, specifically related to improving the pin connection. There is apparently very little written on the coupling itself yet there is a multitude of coupling designs commercially available for use in joining sucker rods. The question arises as to which of these designs is the best. Thus, to aid in the design and selection of a coupling, the purpose of this paper is to evaluate the fatigue life of a number of purpose of this paper is to evaluate the fatigue life of a number of different thread designs which are being used in the manufacture of sucker- rod couplings.

Coupling design has, for the most part, been consistent with the pin design to which it must mate. Thus, coupling design has evolved from the simple cut thread, to a keyhole, burnished, cut and cold-worked and recently, to the fully cold-worked or rolled thread. To the consumer the coupling represents but a part of the cost of a rod. However, to the manufacturer, not all couplings can be made with the same ease and hence, same cost.
EROS--New Observation Vantage Points and Processes
Authors: Fary Raymond W.
Published: December 2007

A paper, the EROS (Earth Resources Observation Satellite) Program of the Department of the Interior, that was presented by W.A. Fischer to the 44th Annual Fall Meeting of the Society of Petroleum Engineers of AIME addressed the subject of this paper. It is the intent of this one to add information on Program developments in the time since that earlier paper and to provide information based on Program experience other than that previously cited.

The EROS Program objective is to utilize aircraft and spacecraft remote-sensing technology as complementary parts of integrated data collection, processing, and dissemination systems to support resources research and management functions of the Department of the Interior. The Program develops and coordinates research in the applications of new sensors for resources applications in cooperation with NASA. At present there are two major areas of activity: present there are two major areas of activity: The first is related to the Earth Resources Technology Satellite (ERTS). The second is a suite of projects designed to determine the applicability of new aerial and satellite sensing systems and techniques to geologic, geographic, hydrologic, and topographic mapping and for supporting natural resources management functions of the Department of the Interior. Programs with similar goals for agriculture and forestry, and for oceanography are being conducted in the Departments of Agriculture, Commerce, the Naval Oceanographic Office, and in a number of colleges and universities.

The first satellite designed specifically for resources research and applications, ERTS-A, is to be launched in early 1972. It will be an unmanned satellite carrying three experimental systems: A three camera Return Beam Vidicon (RBV) system, a 4-band Multispectral Scanning (MSS) radiometer system, and a Data Collection System (DCS). The RBV cameras will photograph simultaneously and instantaneously areas of the earth 100 × 100 nautical miles - or 10,000 square nautical miles - in the blue-green (.475-.575mu m), the red (.580-.680mu m), and the near infrared (.690-.830mu m). The MSS will record three wavelength bands in the same general spectral range and the fourth band (8.0 mu m) will extend farther into the infrared. The DCS will serve to relay data gathered by devices such as stream gages, water-quality samplers, tiltmeters, and geothermal sensors from their surface bases through the ERTS receiving station at the Goddard Space Flight Center to the experimenters.

The satellite will operate for at least 1 year, in near-polar orbit and, weather and clouds permitting, will image any given area every 18 days.
Engineering Geology Review of the February 9, 1971, Earthquake-San Fernando-Sylmar Area
Authors: Slosson James E.
Published: December 2007

The general Los Angeles area was severely jolted by an earthquake during the early morning hours of February 9, 1971. This earthquake was the strongest to affect the Los Angeles area since the 1933 Compton-Long Beach earthquake. The epicenter of the tremor was near the town of Saugus, California; however, the area of surface rupture and greatest damage was some five to six miles southerly in the San Fernando-Sylmar area. Zones of surface rupture were visible within the bedrock of the southern foothills of the San Gabriel mountains and the alluvium of the San Fernando Valley. Belts of extensive damage to structures paralleled or were essentially superimposed over these fault zones. One of the apparent belts extended westerly from the immediate vicinity of the Olive View Hospital toward the interchange of the Foothill, San Diego, and Golden State freeways and the Van Norman Reservoir. This rupture zone is just southerly of a mapped fault referred to as the Hospital Fault but more closely coincides with a fault zone that has little surface expression but has been interpreted from subsurface data. Another rupture zone coincided with the location of a groundwater barrier which suggests geologically recent fault activity.

This earthquake is of great interest, not only from the catastrophic effects that it wrought, but also:

1. the extensive seismic data for research and development of new codes and earthquake design

2. the relatively high acceleration(s) for a magnitude 6.6 earthquake

3. the apparent high angle reverse (or thrust) type of displacement

4. the relatively high magnitude for the apparent distance of rupture

5. the association of the fault type and pattern with the geologic history of the San Gabriel Mountains

6. the effects on nearby oil fields

7. the attempts by the news media to associate oil drilling, the location of the Van Norman Reservoir, and the sun-moon position with the causation.
The History and Philosophy of Oil Insurance Ltd.
Authors: Grattan L.E. , Bruning R.R.
Published: December 2007

The oil company today uses a variety of concepts in its strategy for protecting against accidental loss. Risk transfer, self-insurance and captive insurance are all common to the practice and literature of risk management. Even though this multiplicity of terms can sometimes be confusing, these concepts basically break down into two categories. Risk is either transferred outside the firm to a third party or retained within.

The physical makeup of the oil industry creates certain risks which are virtually uninsurable by the conventional insurance industry. The major contributing factors to this are the generally large size of the individual facilities and the heavy concentration of facilities of many corporations in one geographical area. This difficulty has become evident in an inability of the insurance companies to supply the oil industry with the protection which it desires.

The concept of Oil Insurance Ltd. was developed by a committee of A.P.I. members during 1970 as a solution to this specific problem. It was quickly evident that the solution should be a company, owned by the oil companies themselves, which could dispense cash settlements to its members and fund itself through premiums. Some method had to be developed for sharing the potentially high losses among the members on an equitable basis. Rather than attempt to build a complicated rating scheme considering size, riskiness of assets, and construction-safety procedures the founders chose to allocate premiums on the simple basis of size, followed by modifications on the basis of individual members loss experience. This notion was simple enough to be workable and was deemed equitable by the group. The effective protection offered by O.I.L. is designed to cover the most important elements in the concept of corporation insurance. By providing for protection against cash drain and giving each member the ability to spread his losses over time, this group captive should prove to be a valuable tool to the insurance manager.
K-Factor Theory
Authors: Kaliappan C.S. , Rowe Allen M.
Published: December 2007

It is the purpose of this paper to outline the present state of art for determining K-factors, in particular those which apply to volatile oil and condensate fluids. Equations are presented that can be used to select K-factors for volatile fluids through convergence pressure calculations. These empirical pressure calculations. These empirical correlations can be used for calculating the K-factors for all the components in a mixture, at pressures greater than 0.7 times the convergence pressure. Relations are also presented to compute the K-factors of C+7 presented to compute the K-factors of C+7 fraction as a function of molecular weight, convergence pressure, and the operating pressure. Pressure-temperature phage envelopes pressure. Pressure-temperature phage envelopes are presented for four multicomponent hydrocarbon mixtures that were used in validating the proposed correlations in this paper. proposed correlations in this paper. The current limitation of the equation of state approach for calculating K-factors for volatile fluids is demonstrated through phase diagrams.

Introduction

The U. S. is currently faced with an energy shortage that has resulted in deep-well exploratory drilling (down to 28,000 ft). Reservoirs discovered at these greater depths are more likely to contain volatile fluids, since the reservoir pressure and temperature are higher than those presently being produced at more shallow depths. Due to the nature of these fluids, the ability to calculate reservoir performance and thus predict recoverable performance and thus predict recoverable reserves will, in part, require the accurate determination of their phase compositions and accurate predictions of the densities of the equilibrium phases. The phase composition calculation results in mass conservation, while an accurate phase-density calculation results in the conservation of pore volume. This paper is concerned with the former problem, the accurate determination of the phase compositions at various stages of reservoir depletion. In turn, the calculation of phase compositions requires accurate K-factors. These K-factors are particularly difficult to determine for volatile particularly difficult to determine for volatile reservoir fluids, especially near the critical state.
A Laboratory Investigation of Miscible Displacement by Carbon Dioxide
Authors: Rathmell J.J. , Stalkup F.I. , Hassinger R.C.
Published: December 2007

We have conducted displacements of reconstituted reservoir fluids in Boise outcrop sandstone cores of 6 to 42.5 ft in length using CO2 at various pressures. Our studies indicate that a miscible displacement may be achieved by CO2 injection at pressures well below those necessary when methane is the injection fluid. Miscibility by CO2 is generated through multiple contact equilibria in which the CO2 is progressively enriched with intermediates progressively enriched with intermediates (ethane through hexane) from the oil.

The miscibility pressure for CO2 and a given reservoir fluid is difficult to determine because CO2 exhibits highly efficient swelling and vaporization of the oil. We also found it impractical to operate below the rates where differences in density between displaced and displacing fluids prevent viscous fingering in vertical cores. We were able to define the miscibility pressure using the anticipated increasing recovery as a function of core length in miscible displacements in combination with effluent fluid visual cell observations and chromatographic data.

Introduction

Miscible displacement processes in petroleum reservoirs fall generally into two classes:

(1) processes in which the injected fluid and in-place fluid form a single-phase solution for all compositions and

(2) processes in which the injected fluid and in-place fluid do not on a single equilibrium contact form a single-phase solution over most of the range of possible compositions, but which may generate a zone of contiguous single-phase compositions by multiple contact mass transfer of components between the injected and in-place fluids.

Processes in Class 1 are sometimes characterized as having first contact miscibility; one example of such a process is the propane slug process. There are two important types of Class 2 processes, the enriched gas-drive process and the high-pressure gas process. In the enriched gas-drive process the injected gas contains methane and intermediate hydrocarbons, usually ethane, propane and butanes. These intermediate hydrocarbons dissolve in the oil, enriching it to the point where it becomes miscible with the injected gas. Miscibility in the high-pressure gas process is generated by transfer of intermediates, ethane through hexane, from the reservoir fluid into the injected lean gas. The enriched gas-drive process and the high-pressure gas process are both characterized at pressures where miscibility is possible by an initial period of immiscible displacement until sufficient mass transfer of intermediates has occurred to satisfy the requirement for miscibility.
Addressing BHA Whirl - The Culprit in Mobile Bay
Authors: Mason J.S. , Sprawls Mike
Published: December 2007

SPE and IADC Members

Lateral BHA (Bottom Hole Assembly) vibration, more particularly BHA whirl, is known to be an extremely destructive downhole phenomenon, the occurrence of which is thought to be one of the primary contributing factors to drillstring failure in Mobile Bay.

Unfortunately, indications that BHA whirl is occurring while drilling are rarely evident from conventional surface measurements, especially in deeper sections of wells. Without knowledge of the existence of a problem, avoidance is almost impossible.

For the first time, the potential for the surface identification of BHA whirl is thought to be possible through the measurement of drillstring vibrations. This paper presents data from a well in Mobile Bay where surface vibration measurement and monitoring was conducted while drilling the 12 1/4" hole section.

Axial and torsional data demonstrate characteristics thought to be indicative of BHA whirl which is shown to be associated with accelerated drillstring fatigue, as demonstrated by BHA failures. Various approaches were taken to eliminate the whirl once the phenomenon was recognized, with ultimate success in that the incidence of BHA failure was reduced. Pre-well planning and improved drilling practices resulted in the use of fewer bits and reduced drilling time over the same section on wells previously drilled in the area.

Introduction

Mobile Bay is situated in the Gulf of Mexico off the coast of Alabama and Mississippi (Fig 1), and has acquired a reputation as a harsh drilling environment. Several operators have experienced problems in drilling Norphlet wells in this area. A variety of problems has been encountered throughout these wells, and probably the most problematic phase has been the intermediate section. Numerous drillstring component and bit failures have been experienced while drilling the intermediate section throughout the area. The intermediate section of a typical Mobile Bay well involves drilling from around 6,000 to 18,000 ft.

One operator having drilled five wells in five blocks in the northwest sector of the area encountered drillstring failures throughout the program, with the most severe problems being on the well drilled in Block 916. The intermediate hole size on this particular well was 13 1/2" as opposed to 12 1/4" on earlier wells. During the drilling of the section, numerous failures were experienced which included a twistoff, nine washouts, two broken jars, 34 cracked boxes and five cracked pins.

While there was only one twist off there were several 'near misses' in that cracks in excess of 180 degrees occurred in jars and crossovers. These failures occurred despite a rigorous inspection schedule during which numerous galled and damaged threads were detected in addition to cracked boxes and pins. Other problems encountered were lost cones from three bits and eccentric wear to drillpipe.

P. 19
The Specification, Design and Construction of Rig 200
Authors: Meakin Chris , Hampton Sam , Quintero Alan
Published: December 2007

A state-of-the-art mechanized drilling rig has been built to drill development wells on the West Tuna platform, Australia's first concrete gravity structure.

This paper discusses how early attention to the design philosophy, effort in preparing the specification, early involvement of operations personnel, and close co-operation between Esso and AOWT during the rig design and fabrication resulted in a cost effective rig.

The paper describes innovations to the base design of the pipe racking system and the integrated driller's cabin (from which equipment can be remotely controlled), and the use of techniques such as HAZOPs, human-machine interface and ergonomic studies. Special attention is paid to design enhancement on the rig floor.
Drilling Directional Holes Having Constant Curvature
Authors: Dareing D.W.
Published: December 2007

Introduction

It is sometimes desirable, when drilling for oil and gas, to drill away from the vertical so that the bottom end of the wellbore is at a given horizontal distance from the vertical. These wells are called directional wells and are drilled from offshore platforms to reduce the number of offshore structures in a particular oil or gas field. At the present, directional wells are drilled somewhat by trial-and-error, i.e., measurements of drill bit orientation are made periodically and appropriate changes are made in weight on the drill bit to increase or decrease the orientation of the bit. Stabilizers are also used near the bit to control the rate of hole deviation from the vertical.

There are several articles in the literature which discuss directional drilling (and hole deviation, crooked holes, dog-legs, etc.); however, except for very few technical papers, most of the publications are general discussions of the directional drilling problem. A literature survey indicated there are very few, if any, technical publications that relate drilling variables to wellbore curvature.

In 1968, the API funded a 3-year research project (API Research Project 107) at the U. of project (API Research Project 107) at the U. of Arkansas to study a directional-drilling concept proposed by the author. The directional-drilling proposed by the author. The directional-drilling concept is based on the premise that a wellbore, having constant curvature, will be drilled if the curvature of the drill collars directly above the bit is constant while drilling the hole; the deflection of the drill collars directly above the bit is a circular arc. The concept presupposes that the bit will drill in the direction it is pointing. The direction of the bit is controlled pointing. The direction of the bit is controlled by collar deflection that, in turn, depends on collar design and bit force. The research began by developing and solving a nonlinear differential equation of bending, which leads to collar design data. This phase was followed by an experimental phase, designed to verify the premise mentioned above. This paper summarizes premise mentioned above. This paper summarizes the results from the 3-year API project. The experimental work is presented first and is followed by the bending theory.

LABORATORY DRILLING RIG

A laboratory drilling rig (Fig. 1) was designed and built to experimentally verify the directional-drilling concept mentioned above.
Tide Flow: A Low Rate Density Driven Cementing Technique for Highly Deviated Wells
Authors: Kroken W. , Sjåholm Å. J. , Olsen A. S.
Published: December 2007

Over the last five to ten years the oil industry has undergone major changes. Increased focus on increased recovery has led to the development of techniques aimed at achieving longer, highly deviated and horizontal wells which penetrate several targets in a given reservoir.

This paper outlines an alternative cementing technique to the more common turbulent or effective laminar placements and describes two cases where this technique were used at the Gullfaks Field. By using of the density difference between the displaced and the displacing fluids, the mud in the narrow part of the annulus will float up into the wide part of the annulus and be carried away. The effect will be optimised with the use of a low pumping rate, which improves the ability of the fluids to exchange. This technique can be more cost effective than stage-cementing or increasing the hole diameter.

This technique is recommended when turbulent or effective laminar displacement is difficult.
How a 23000' MD Extended Reach Horizontal Well was Drilled in Less Than 24 Days
Authors: Omsberg N. P. , Morgan D. R.
Published: December 2007

From spud to TD, the Joanne 30/7a-Pl 1 well was drilled to a measured depth of 23,035' in 23.65 days. This extraordinary performance was achieved despite a 1600' sidetrack in an upper hole section. Adding time for skidding over the well slot, logging the reservoir interval, running and cementing the production liner and suspending the well brought the total time on the well to 31.65 days. The horizontal displacement for this extended reach well is 18,560', including a 4287' horizontal section in the thin Palaeocene Andrew sand reservoir.

PI 1 was the eleventh well drilled on the Judy template using the Santa Fe Galaxy jack up drilling rig in Phillips J-Block development The drilling program featured a diligent and continuous search for methods to improve performance. This resulted in the implementation of several innovations during the course of the project A continuous improvement trend was clear throughout the template drilling project culminating in the PI 1 well. Several world records were set while drilling this well, including the 24 hour footage and total footage in a single run.

This paper will present the techniques used in the P11 well to show how the impressive result was achieved.
Integrated Geologic, Engineering, and Financial Assessment of Gas Displacement Recovery in Texas
Authors: Beike D. K. , Holtz M. H.
Published: December 2007

A total of 57 commercially viable gas-displacement projects in Texas are classified into seven depositional environments. We collected reservoir and petrophysical data and depth and oil gravity for each reservoir, which gave us a generalized case model for each depositional environment. We also collected and analyzed information about the design of these projects, concentrating on pattern, spacing, and production processes previously applied.

Cost calculations that are presented are in accordance with a previous cost study by Beike and Holtz.1 Finances were analyzed for the case model of each depositional system according to net present value and internal rate of return. We also used an economic sensitivity analysis to investigate the effect of oil price, well spacing, and incremental recovery.

The potential for reserve additions from CO2 flooding in Texas is substantial. An additional 1,730 reservoirs are candidates for gas-displacement recovery. This set of reservoirs contains 70 BSTB of original oil in place, 23 BSTB of mobile oil, and 37 BSTB of residual oil. Factoring in a conservative reserve growth recovery of an additional 10 percent of original oil in place, we estimate that future GDR projects could produce 7 BSTB in Texas. Most of this reserve growth will continue to come from restricted to open-platform carbonate reservoirs in West Texas.