bluuebunny/crossref_metadata_2025 huggingface dataset:
Application of Minimum Cost Drilling Programs
Authors: Cole Frank W.
Published: December 2007

Minimum cost drilling programs have been available for about 10 years, but only recently have they been utilized to any extent. One of the principal disadvantages of most programs is that they assume rig operating costs are independent of bit weights and rotary speeds. Although the use of minimum cost drilling programs is relatively new, their proper use programs is relatively new, their proper use can effect substantial savings in the drilling operation.

The principal uses of a minimum cost drilling program are in (1) planning the entire well, (2) selecting the proper bit, (3) optimum time to pull a bit, (4) proper weight and speed to meet special conditions, such as extending bit life in order to save a round trip, reducing bit life as a result of changing formations, critical rotary speeds and crooked hole conditions, (5) revising optimum bit weights, rotary speeds, and bit footages on an instantaneous basis during drilling and (6) studying special problems such as the influence of rig costs on optimum drilling conditions.

Minimum cost drilling programs can be economically used with a time-share computer and a teletype terminal. The terminal can be located at the rig or in the office.

Most minimum cost drilling programs in use today are more complex than they need to be. A relatively simple program should be used initially; then, as more experience is gained, the programs can be made more complex.

Introduction

Since the late 1950's, as evidenced by the published petroleum literature, there has been published petroleum literature, there has been a strong interest in developing mathematical relationships which would describe and, therefore, permit some type of optimization of the drilling operation. Beilstein and Cannon made an important contribution to understanding the interrelationships of some of the more important variables affecting the economics of drilling. Speer later published valuable data which largely supported the observations of Beilstein and Cannon. Within a short period of time a number of analytical methods for describing the drilling operation were published. All of these methods were developed published. All of these methods were developed primarily to study the effects of varying bit primarily to study the effects of varying bit weights and rotary speeds on penetration rates and drilling costs. These analytical methods are now commonly referred to as minimum cost drilling or optimized drilling methods. A true minimum cost drilling program must include all variables influencing the drilling operation. Some of the most important of these variables are (1) drilling rig, (2) crew efficiency, (3) hydraulics programs, (4) type of mud, (5 bit selection (6) bit weight and (7) rotary speed.
Driller's Challenge: The 28,000 Foot Hunton
Authors: Muscovalley J.N.
Published: December 2007

The deep Anadarko Basin is expected to become a major gas producing province within the next decade. The Hunton formation, sometimes occurring as deep as 28,000 feet, is the primary objective of today's gas exploration in the Basin.

The drilling industry faces the challenge of providing the equipment, and technology, to drill wells of this depth on a continuous and economical basis.

Because of the many wells drilled below 20,000 feet in the past five years, the industry today has the experience and the technical ability to successfully meet this challenge.

Introduction

The Petroleum Industry must find new gas reserves. The Anadarko Basin, long one of this nation's major gas producing provinces, now is being explored to it's deepest extent for this gas. This nation's continuing need for energy has made what once seemed uneconomical and impractical, a necessity.

Today, the Hunton formation of Devonian age is one of the primary targets for this deep gas exploration. There are presently several wells drilling to the Hunton, which may occur as deep as 28,000 feet.

A few years ago, a 28,000 foot well would have been totally uneconomical. Deep drilling, at that time, had not become the routine matter that it is today, and the demand for gas had not reached the point where gas transmission companies were point where gas transmission companies were willing to bid for the gas before the well was spudded. The combination of these two facts, the improvement in drilling and the improvement in the supply and demand for gas, has made the 28, 000 foot well a reality.

However, a well of this depth still represents a tremendous challenge to the industry. Well costs in excess of 2 million dollars, well depths deeper by 2, 000 to 3, 000 feet than any ever drilled, unknown geological problems, and finally the risk of wildcatting at any depth, makes this one of the most dramatic challenges the drilling industry has ever faced.
Geological Elements Involved in the Exploitation of Deep Reservoirs
Authors: Moore Carl A.
Published: December 2007

A knowledge of the geometry of the rocks in the increasingly deeper basin areas may provide significant geological elements which can affect drilling and completion procedures.

In the Mid-Continent "hard rock" country, porosity variations at depth do not follow the pattern that is recognized in the soft Gulf Coast sediments. Porosities in sandstones may vary with the presence of shale beds which are subject to compaction by overburden presence of shale beds which are subject to compaction by overburden pressures; and by factors of re-arrangement of grains accomplished pressures; and by factors of re-arrangement of grains accomplished through crushing and re-cementation. Grain size distribution and initial porosities will be factors to be evaluated. Fairly coarse, non-shaly, beach sands can be expected to porosity at depths, than deposited in deep water, are shaly. These latter poor porosity because of overburden pressures, as re-arrangement factors.

Limestone porosities averaging over 12% are being reported from Hunton (Devonian - Silurian age) limestone reservoirs below exhibit greater those sands which were below wave base, that types will exhibit compaction due to well as the 20,000 feet. Because of the rigid rock fabric, porosity in limestones is not expected to be a function of depth of burial. Rather, the environment of deposition will affect the primary porosity. The geologic history, of the record of periods of deposition, uplift, and mountain building movements in the area, will be the most significant factor in the development of secondary prorosity from which giant gas production is being proved.

The degree of dolomitization of limestones is another factor in the development of porosity. There is usually a straight line relationship between the increase in dolomite content of a limestone and its increasing porosity. Evidently dolomitization is an early phenomena, controlled by the depositional environment of the limestone and the diagenetic changes which are imposed upon the new rock. Any petroleum that is generated in a basin may move into the porous limestone reservoir rock from an adjacent shale source rock.

Increased fluid pressures at depth may initiate micro-movements along minute fracture planes, and thus add a factor to the drillability of a given rock, and may influence the migration of fluids.
How to Select the Correct Sand Control System for Your Well
Authors: Coulter A.W. , Gurley D.G.
Published: December 2007

There has long been a need for a guide to the selection of the sand control system needed for a particular well. There are four types of systems in use today:

(1) screens, gravel packing,

(2) sand consolidation and

(3) a resin-coated particulate such as sand.

Although universal agreement may not be possible at this time, there are certain guidelines that are followed. The factors involved include formation permeability, clay and silt content of formation, interval length, number of zones, homogeneity, well history, type completion, depth, expense of rig time and others. This paper will consider these factors and their influence on the selection of sand control systems.

Introduction

The problem of controlling sand production in oil and gas wells has increased significantly in importance in the past few decades as new offshore oil provinces have been discovered and developed. The oil produced in many fields, particularly in south Louisiana, offshore Louisiana and California could not be economically produced if effective means of sand control were not available. Many papers have been published over the years describing the various sand control systems available to the industry. Much has also been written concerning the proper techniques for applying the various systems. There is no doubt that much progress has been made in solving the problem of sand control. There remains, however, a great degree of controversy and much divergence of opinion as to which method of sand control should be applied in any particular situation. Admittedly, this is a controversial problem, but the authors feel that certain guidelines can be established on the basis of experience with the various systems in use. The purpose of this paper is to review the four main methods of sand control that are in widespread use and to discuss those factors which are most important in the selection of the method best suited for a particular well.
Taber South - Canada's First Polymer Flood
Authors: Martin Ian , Lozanski Wally
Published: December 2007

Three years of actual performance of the Taber South Mannville B pool polymer flood has resulted in sufficient data to review the initial decision to implement this type of secondary recovery scheme. Comparison of performance to the original forecasts to a performance to the original forecasts to a critical re-examination of those forecasts and to performance of conventional waterfloods in pools with similar characteristics has been pools with similar characteristics has been made. Operating costs and capital costs caused by polymer injection have been studied. Consideration of ultimate polymer slug size and operational procedures has been undertaken to provide a guide for optimum future performance. provide a guide for optimum future performance. The conclusion has been reached that polymer flooding has been economically successful and appears to have been significantly more profitable than a conventional waterflood.

Introduction

Canada's first polymer flood was initiated in Feb., 1967, in the Taber South Mannville B oil pool, located approximately 35 miles southeast of Lethbridge, Alta. (Fig. 1).

The Taber South Mannville B pool was discovered in March, 1963, with the drilling of the CPOG Taber S 2-29-7-16 well. A total of 23 oil wells and 11 dry holes drilled on a 40-acre spacing pattern, to an average depth of 3,230 ft, defined a reservoir containing an estimated 40,010,000 STB of oil.
Long Stroke Pumping Unit
Authors: Ewing Roy D.
Published: December 2007

The success of the sucker-rod system for pumping oil wells is due, primarily, to the pumping oil wells is due, primarily, to the simplicity of the surface, as well as the subsurface equipment. In the early life of the industry the wells were shallow and could be adequately pumped with beam-type surface equipment. As wells were drilled to greater depths and larger volumes had to be pumped, consideration was given to other types of surface equipment to actuate the sucker-rod system.

Some of the advantages of long-stroke pumping are (1) fewer stress reversing cycles pumping are (1) fewer stress reversing cycles resulting in longer sucker-rod life, (2) more net plunger travel as related to polished rod travel, (3) longer subsurface pump life due to reduced number of pumping cycles and increased area of wearing surfaces in the pump, (4) less tubing and sucker-rod coupling wear in crooked or slant holes and (5) less frequent servicing of subsurface equipment.

The long-stroke pumping unit covered by this paper has the following advantages in addition to those listed above:

(1) increased production due to uniform polished rod velocity production due to uniform polished rod velocity (this is highly important in pumping viscous liquids),

(2) less reducer torque due to short torque arm and

(3) more horsepower developed by a given reducer due to higher rotating speed of the drum shaft.

There may be some question as to what constitutes long-stroke pumping of an oil well. Twenty years ago a beam-type n unit with a 100-in. stroke was considered to have a "long stroke". As the requirement for pumping more liquid from greater depths developed, beam-type units were made larger and with longer strokes to satisfy this demand. There is now one beam-type pumping unit available with a maximum stroke length of 300 in. It is difficult to say what the limit will be on length of stroke for a beam unit. It will probably be determined by the degree of success of some other type unit, such as the one to be discussed.

A number of long-stroke pumping units have been built with varying degrees of success. They were generally limited by mechanical design problems or adverse effects on other components problems or adverse effects on other components in the pumping system.

Influenced by the old adage, "If at first you don't succeed, try, try again", another design* of a long-stroke pumping unit was conceived and the advantages of long-stroke pumping have been achieved to a very high degree. pumping have been achieved to a very high degree. The key to the success of this unit is a contoured drum for spooling wire rope assemblies to actuate the sucker-rod string and suspend the counterbalance. Fig. 1 shows an installation of the long-stroke pumping unit. The stroke length is 34 ft and the polished rod-load capacity is 35,000 lb. Two geared speed reducers have been built with ratings of 310,000- and 420,000-in. lb peak torque capacity. Maximum recommended input hp to these reducers is 75 and 100, respectively.
The Interdependence Of Free World Nations On Their Petroleum Supply
Authors: O'Brien Jerome J.
Published: December 2007

UNITED STATES DEPARTMENT of the INTERIOR * * * * * * * * * * * * * * * * * ** * * * news release

For Release to PM's, FEBRUARY 19, 1962

It is with greet pride that I have the privilege of addressing you today the Society of Petroleum Engineers of the A.I.M.E. This occasion is serving at wofold purpose for me; en opportunity to fraternize with many of my old friends and colleagues, end the honor of addressing en organization of which I am a card-carrying member. It is always a pleasure to meet with an engineering group because, in my opinion, there are more men of genius, pluck and determination to win, engaged in engineering then in any other profession.

The word "interdependence" has perhaps been too widely used recently, but whether we like it or not, the problems of oil are entwined with broader problems everywhere.

The petroleum industry of the Free World today is deeply influenced by two dominant sets of factors that give rise to severe stresses within the industry's structure and create major uncertainties as to the future direction of its development.

The first of these elements is the worldwide excess in the capacity to produce, to refine, and to transport oil. This progressive imbalance between world consumption of petroleum products and ability to produce is generating intensive, and sometimes disruptive, competition in oil marketing. It is creating instability in the entire world petroleum price structure.

The second cause of stress is far more complex. It is a reflection of the new trend in world affairs characterized by the fading of the colonial system end the emergence of a succession of new, inexperienced, end sometimes unstable political units. Radical changes are occurring in many areas where established social end economic patterns are being put aside or are under attack.

RESERVES OF CRUDE OIL AND NATURAL GAS LIQUIDS

Some of the fundamental problems relating to petroleum are revealed by examination of the contrast between the location of the major consuming area send the location of the major oil reserves of the Free World. The consumption of oil, of course, is concentrated in the industrially developed areas such as the United States and Europe, whereas most known reserves are located in less developed areas such as the Middle East.
The Case for Oil Spill Dispersants
Authors: Canevari Gerard P.
Published: December 2007

The subject of oil spill handling represents a new area of technology that is unique in that it encompasses chemical, mechanical and biological disciplines. Within this subject the use of chemical dispersants represents a solution that can provide the most applicable approach under certain conditions.

This paper defines the overall problem of oil spills and then derives the basis for the use of dispersants, as well as the conditions that justify their use. Chemical dispersants are not a panacea for the cleanup of oil spills. However, there are situations where dispersants should be used for the benefit of our natural resources; and there are also instances where they should not be used.

An appreciation of the dispersing mechanism and the influence of environmental factors is necessary in order to assess the appropriate role for dispersants in the handling of oil spills.

Introduction

It is important at the outset of any discussion regarding oil spill dispersants to review the subject of oil spills in general in order to consider the use of dispersants in the correct perspective. The subject of oil spill handling is complex as it encompasses several engineering disciplines, as well as biological, conservationist and political interests.

This paper will derive the specific area of application for dispersants and will review the pros and cons regarding their usage. At the outset, it should be outlined that the role of oil spill dispersants is one of a last resort nature since prevention of oil spills is the first consideration. In the industrial and governmental communities, the major effort has been directed toward this area. There is extensive ongoing research, for example, ranging from operational areas, e.g., collision avoidance techniques and training, to more novel approaches such as gellation of crude oil cargo to prevent release from a damaged compartment, oil-water separation devices, flocculating agents, etc.

However, after a spill has occurred, physical containment and removal is the physical containment and removal is the recommended approach. This is the most complete solution to the problem. Unfortunately, the present state of the art limits the effective present state of the art limits the effective application of oil containment booms to rather quiescent conditions and they are not suitable in general for open sea conditions. As concisely summarized by Dewling, there are at least 37 different approaches to corralling and holding oil spills. Spill boom systems are available in prices ranging from $5 to $45 per foot and represent an important tool under those sea, weather and geographical conditions that permit effective deployment. There is extensive research currently underway in this area, principally funded by the U.S. Coast Guard, to principally funded by the U.S. Coast Guard, to extend the capability of spill booms.
Application Of Leaky Aquifer Theory To Testing Of Aquifer Gas Storage Prospects
Authors: Witherspoon P.A. , Neuman S.P.
Published: December 2007

A much more complete theory of transient flow in leaky aquifers has recently been developed and can be applied to the problem of investigating the hydraulic properties of caprock layers over potential gas storage reservoirs. During a pumping test, the transient behavior of a multiple-aquifer system depends on the properties of the aquifer being pumped as well as the degree of communication that can develop across the pumped as well as the degree of communication that can develop across the caprock to unpumped aquifers. However, at sufficiently small values of time defined by tD less than 1.6 Beta /(r/B), the effects of the unpumped aquifer can be ignored and the caprock can be treated as though it were semi-infinite.

The application of this new theory to the problem of testing aquifer gas storage prospects is reviewed, and it is shown that the theory provides a better understanding of earlier concepts on slightly leaky caprocks. The general applicability of the method is demonstrated by analyzing data from field tests on two different aquifers with very leaky caprocks. The results are in excellent agreement with core analyses of the caprocks.
Shell's Experiences on the Cedar Creek Anticline, Montana, with Blended HCL Acid-Unibead* Mixtures to Continuously Divert and Stimulate Carbonate Reservoirs
Authors: Hayden Brian R.
Published: December 2007

This paper presents Shell Oil Company's experiences in stimulating producing, water injection, and water source wells on the Cedar Creek Anticline In Montana, using a blended HCL acid-Unibead* continuous diversion and stimulation technique. Wells not amenable to effective stimulation using conventional methods of zone isolation and acid placement because of problems in well mechanics are currently being stimulated using the continuous diversion and stimulation technique with favorable results. The use of surface blended mixtures of HCL acid and Unibeads to stimulate problem wells is considered to be more effective than the more widely used "slug-plug" diversion and stimulation technique, and to have wider application, especially for treating wells on the Cedar Creek Anticline.

The results of 30 treatments on producing, injection, and water source wells performed to date using the continuous diversion and stimulation technique are presented, along with the reasons for the use of this technique, observations made, conclusions reached, and recommendations for future use.

Introduction

Shell Oil Company began using a continuous HCL acid-Unibead* stimulation technique during December 1969 to acid treat impaired wells on the Cedar Creek Anticline in Montana completed in as many as 16 porous Silurian-Ordovician and 4 Mississippian carbonate intervals. Because of well mechanics, many of these wells were not amenable to effective stimulation using conventional methods of zone isolation and acid placement (such as a retrievable bridge plug and packer arrangement).
The Real Story of Cement Expansion
Authors: Root R.L. , Calvert D.G.
Published: December 2007

One of the most serious problems encountered when cementing casing in a well is the failure of the cement casing and cement formation bond. The failure of the cement bonding is a major problem from the standpoint of allowing problem from the standpoint of allowing migration of fluids from one zone to another. Also, poor bonding can result in large losses of reservoir fluids, premature reservoir depletion, and unsatisfactory stimulation operations. With these factors in mind, it has long been recognized that superior cementing operations could be achieved if expansion could be induced in oil well cements. Expansion currently is induced in oil well cements by two methods, addition of salts (salt cements), or addition of an expanding component (chemically compensated cement).

The purpose of this paper is to compare the expansion characteristics of these types of cements. Additional characteristics such as pumping time, compressive strength, and bonding pumping time, compressive strength, and bonding are also compared.

Introduction

Good bonding of the cement to pipe and cement to formation is essential for effective zone isolation. This problem is evident in oil, gas, and gas storage wells. Secondly, poor bonding may limit the desired production and stimulation techniques of the well in question. The introduction of expansion in a well cementing system has long been recognized as a possible means of improving the primary cement job. At present, these are four basic methods that may be used to accomplish better bonding.
A Mathematical Analysis of Oil and Gas Well Stimulation by Explosive Fracturing
Authors: Laspe Charles G. , Roberts Leonard N.
Published: December 2007

Considerable interest in chemical explosive fracturing has resulted in the derivation of mathematical reservoir models for explosive stimulations. Mathematical models are presented which describe the effects of a chemical explosive displaced into a producing formation and the characteristics of the drainage system within the formation after stimulation. The effects on formation permeability and fracture extension distances permeability and fracture extension distances for different types of formations are derived. Predicted over-all production improvement Predicted over-all production improvement ratios and the economics involved are also covered.

Introduction

In a recent article, a new technique of explosively stimulating the production of oil and gas wells is described by Weigelt and Laspe. The method involves the hydraulic or pneumatic displacement of a powerful slurried pneumatic displacement of a powerful slurried explosive far back within the fracture system of the pay zone. Upon detonation, which propagates through fissures as small as 1/64 in. propagates through fissures as small as 1/64 in. in width, high energy shock waves are initiated. These waves cause extensive rubblizing and secondary fracture generation at considerable distances from the original fissure. In addition, the large quantity of product gases generated by the explosion result in lengthening of the primary fracture system. The rubblized fragments, some of which are in the typical frac sand particle size range, are blown into the newly formed fractures to provide an autogenerated proppant.
A Laboratory Investigation Confirms the Relative Inefficiency of True Miscible Drives, and Outlines New Concepts for Maximizing Oil Recovery by Gas Injection
Authors: Giraud A. , Thomere R. , Gard J. , Charles M.
Published: December 2007

Laboratory displacements of oil by gas at high temperature and pressure have been performed in one and two dimensions using both performed in one and two dimensions using both simple ternary mixtures and actual reservoir fluids. The results have been analysed with the help of a numerical model.

The displacements carried out in the so called "dynamic miscibility" conditions are fundamentally different from true miscible displacements, in particular the conformance appears to be much better when optimum conditions (pressure and/or gas compositions) are selected. These conclusions may be extended to all displacement processes involving mass transfer between phases.

Introduction

Several types of displacement processes are commonly referred to as "miscible", although they do not involve identical thermodynamic conditions. Fig. 1 represents the classical ternary diagram, in which complex hydrocarbon mixtures are schematically described as a combination of three main constituents: methane (C1), intermediate hydrocarbons (C2 to C6) and heavy hydrocarbons (C7+). Although this diagram is only a crude approximation of the complex PVT behaviour of natural hydrocarbon mixtures, it is very convenient and good enough qualitatively for demonstration purposes.
Produced Water Disposal – A Learning Curve in Yemen
Authors: Wilkie D. I. , Kennedy W. L. , Tracy K. F.
Published: December 2007

The success of many oilfields depends upon efficient disposal of produced water. In the case of the Masila block in Yemen, the difficulty of water disposal was underestimated because the high permeability of the production wells led to expectations that high injection rates and economic subsurface disposal would be easily attained.

A number of standard approaches were taken to obtain injection rates of 40,000 BWPD per well. After initial failures, a multi-disciplined team was formed to review the practical and theoretical aspects of formation damage and water quality. Successful injection at rates exceeding 80,000 BWPD per well were subsequently achieved by underbalanced drilling and improving water quality. Two orders of magnitude of increase in injectivity index. Optimizing the drilling and completion methods saved S14MMUS that would have been needed to dispose of water at hydraulic fracturing pressures.

The learning curve and dead ends that led to the successful subsurface disposal of over 200,000 BWPD are described. Perforating, core flow tests, core analysis, corrosion, sand behavior, pressure measurement, drilling fluids, completion configuration, filtration and remedial stimulation are discussed.
Deepwater Skid-over Solution for Marginal Field Development at the Froy Field
Authors: Smidth Frederik , Georges Christian
Published: December 2007

1 Drilling in skid-off (tender assisted) mode from a cantilever jack-up has been done on several occasions worldwide including the North Sea (ref. 1).

This paper describes the utilization of the "MAERSK GALLANT", an MSC-C.T62S jack-up drilling rig, at the FROY Field in the North Sea in Skid-off Mode.

FROY is located 35 km SE of the Frigg Field off Norway in a water depth of 120 m. The field is developed with a light, unmanned platform. The topside is comprising a well bay area with 15 slots and a process area with a test separator, a gas/liquid separator and export pump only. No drilling facilities are built on the WHP. Four wells were pre-drilled with a semi-submersible rig. Tie-back and completion of these first four wells and completion and drilling of the six remaining wells were performed by the jack-up "MAERSK GALLANT" in skid-over mode (fig. 1).

Several development scenarios were studied. The reason to develop this field with this alternative, even in this extreme environment, was to minimize weight and cost; the jacket structure is 6,000 mT and the topside only 2,375 mT. It has also been a focus in the design of the skid-over solution itself and thereby make it more or less "field specific", compared to previous skid-off solutions for ultra harsh environment jack-ups (ref. 1).

Another consideration was the water depth of 120 m, which is a North Sea record for jack-ups, and the associated relative movements between the production platform and the rig.

The end result, however, was a highly flexible design which can be utilized on a large number of field developments with only minor adjustments.

All setting up of drilling facilities on the platform were done from the jack-up without any assistance from the platform, crane barges or similar.

As for the drilling operation all "support" from the production platform is two skidding beams with a spacing of 14.0 m (46 feet).

The design optimization was done as a joint effort between the Operator (ELF NORGE) and Maersk Drilling. The success of the project emphasized the importance of close cooperation between the operator and the contractor as early as possible in connection with field development projects.
Slim Hole Drilling and Well Intervention from a Light Vessel
Authors: Carstens E. , Ervik G. A. , Gleditsch S.
Published: December 2007

Drilling in deep waters is a costly venture. This paper discribes how the method of slim hole drilling may be applied to reduce those costs. A system is designed for 5000 ft water depths which incorporates a heave-compensated singles rig and high pressure riser. The rig is fully heave-compensated while tripping and drilling allowing better control of downhole operations. The high pressure riser dispenses with the need for kill and choke lines. The smaller and simpler design enables use of quick couplings, and bouyancy elements are not needed. The vessel is dynamically positioned. The subsea system is designed to allow for drift-off to occur with the riser intact and well control maintained. This paper describes the system and tests and evaluations done to determine system cost and efficiency. A market evaluation shows that the highest potential for cost reduction is for subsea well intervention and deep water exploration drilling.
Evaluation of Oil Soluble Resin Mixtures as Diverting Agents for Matrix Acidizing
Authors: Crowe C.W.
Published: December 2007

A new oil soluble resin mixture has proved extremely effective as a diverting agent for matrix acidizing treatments. The mixture has three major advantages which make it a more effective diverter than other agents currently in use:

1. It effectively equalizes flow into zones of varying permeability.

2. It is completely oil soluble and leaves no residual formation damage.

3. It can penetrate a gravel pack and divert in the formation behind the pack. It is the only diverter which is effective for this application at temperatures above 125degrees F.

One of the major factors controlling the success or failure of any sandstone matrix acidizing treatment is that of proper distribution of the treating acid over the entire producing interval. Unless an effective diverting agent is used, the largest portion of the acid may be expended on only a small part of the total zone.

A study was made of the various diverting agents presently used in matrix acidizing. These diverters were evaluated in terms of (1) their ability to equalize acid flow into zones of varying permeability, and (2) clean-up following the treatment without residual formation damage. Diverters evaluated included viscous gels, natural gums, emulsions, acid swellable polymers, solid organic acids and a new system employing a mixture of finely divided oil-soluble solids.

Of the materials tested, some were found to be totally ineffective while others produced extensive formation damage. Best diversion was obtained with the swellable polymers or the mixture of oil soluble resins.

This paper presents data comparing effectiveness of various matrix diverters. The diversion mechanism of the oil soluble resins is described and case histories are presented to show how better diversion improves production increases.

Introduction

In recent years, renewed interest has been shown in the use of hydrochloric-hydrofluoric acid mixtures for the matrix treatment of sandstone formations.
Rheology Design to Optimise Rate of Penetration
Authors: Maidla E. E. , Reay A. J. , Beck F. E. , Tan C. P.
Published: December 2007

A Bit Reynolds Number optimization algorithm has been developed in response to the field observation that this maximizes the rate of penetration regarding bit hydraulic effects.

Discussion on the reasons for such behaviour are undertaken and some common drilling scenarios are presented for which Bit Reynolds Numbers would be of use.

A field case study shows good agreement between the theoretical optimum and the field results.

A possible downside for maximizing Bit Reynolds Numbers is also addressed concerning wellbore stability.
Critical Evaluation of Blast Furnace Slag Mud Converted to Cement
Authors: Sabins F. L. , Edwards T. M. , Maharidge R. L. , Weiss M.
Published: December 2007

This paper summarizes the results of a Joint Industry Project investigating the performance of mud converted to cement using Blast Furnace Slag (BFS). This paper compares BFS/muds to conventional Portland cements in various simulated cementing applications. This project covers the test results from converting dispersed and PHPA drilling fluids to cement, in comparison to conventional low fluid loss Portland cements in three main areas. The first tests simulated a geopressured gas well by use of a large scale gas migration model. Secondly the dimensional stability of the BFS/mud is presented. Dimensional stability measures the total volume reduction at temperature and pressure during the hydration process. Finally the mechanical properties of the system are also presented including: compressive, tensile, and shear strengths and long term creep under confining loads. The tests showed that the BFS and the Portland systems display similar physical characteristics, but do exhibit some differences. Common traits were: hydration volume reduction, pressure reduction due to volume losses and gellation, compressive strength, shear strength and long term creep. In the limited testing performed the BFS/mud system, however, did exhibit much lower tensile strengths and demonstrated an inability to maintain a long term gas seal in the latter stages of hydration. Further testing is planned to better understand this latter phenomenon. A detailed analysis of this data is given in this report.
Liquid Cement Premix Introduces New Solutions to Conventional Cementing Problems
Authors: Rae Phil , Johnston Neil
Published: December 2007

Oilwell cementing has changed very little in the past 70 years. However, a new process has been developed that radically changes the way in which cementing operations are conducted. A new understanding of material properties has allowed the design of novel cementing systems, with remarkable performance characteristics, that can be mixed more easily in the field. These slurries can be accurately mixed with simple equipment but, if required, the process can be fully automated.

Control of critical slurry parameters, such as density, rheology, thickening time and compressive strength development can now be achieved with unprecedented precision without the use of batch-mix tanks or other ancillary equipment. Using this process, continuous ("on-the-fly") cementing operations can be conducted at rates ranging from 0.1 – 3.5 cu. m per minute (approximately 0. 5 – 20 bbls/min) without the problems that typify today's methods. Slurries that can be prepared in this way cover the wide density range encountered in the majority of cementing applications, 1320 – 2500 kg/cu. m. (11 – 21 lbm/gal). Furthermore, slurry properties can be continuously modified throughout the operation, if required, to take account of well temperature profile, etc. Such procedures help reduce waste and minimise environmental impact of the cementing operation.

The new process can be used advantageously both for primary and remedial cementing operations and is applicable both on-land and offshore. We believe the greatest benefits can be realised in the offshore sector initially since the process lends itself to full automation, permitting reductions in personnel-on-board, improved safety and reduced rig time. Ultimately, the improved wellsite quality control achieved with this system will translate to a higher percentage of successful cementing operations and a net reduction in cost for the operating companies.
High Performance Water Reduced Cement Slurries Prepared With Low Cost Optimized Blend
Authors: Baret J. François , Garnier Andre , Rashad Basil
Published: December 2007

A cement slurry is a suspension of solid particles in an aqueous solution. Slurry properties depend on many variables: the amount and nature of the solids, including cement, the additives used, the amount and the type of water, the temperature and the pressure.

For a given solid blend, the water-to-solid ratio determines the slurry density. In the new approach to cementing described in this paper, differently to what is done traditionally, a blend has to be chosen as the first step in the system selection. Here the blend choice is a process which implies the identification of the materials providing the specific gravity required and the determination of the optimal ratios between these different components.

Blend quality is an essential parameter which plays a role, directly or indirectly, in all slurry properties.
Optimization of Drilling Performance in Argentina through a New PDC Bit Generation
Authors: Besson A. , Delwiche R. , Lamine E. , Dekoster C.
Published: December 2007

The lithology of the North West of Argentina presents two major portions where PDC bits have not succeeded in the past. The first portion was mainly made up of alternating sands and shales with spot zones of conglomerates erratically encountered. The second portion was made of dense shales and cemented sandstone stringers, with altemances of limestones. In spite of acceptable performance on the top portion, conventional PDC bits faced premature failures when the compacted sandstones and limestones were faced. Rock bit performances were usually in the range of ± 6 to 7 m/h and the footage around 360 m. The section was drilled with five to six bits for a total drilling time of 220 hours. The introduction of a new generation of PDC bits allowed to triple the ROP and increase by five times the potential footage.

This paper describes the methodology and shows the efficiency of a good partnership between the operator and the service company; a good level of communication, a knowledge of mutual skills and expectations, as well as a prompt reaction from both sides led to the definition of a reliable product using the latest developments of the PDC bit technology:

the ability to control the quality of the PDC cutters, the use of an advanced cutter lay out defined by 3-D software, the use of CFD code for optimized cleaning and cooling, the mastering of vibration reducing features, including spiralled blades etc.

Savings in the range of 200,000$ per well were recorded at the first trial of a drilling program. Fine tuning of the technology and parameters now allow savings beyond 350,000$ per well.
New Hard Formation Roller Cone Bit Technology Improves Economics of Abrasive Travis Peak, Cotton Valley Wells
Authors: Watson P.A. , Welch R.M. , Scott D.E.
Published: December 2007

The typical gas wells drilled in heavily explored Panola County of East Texas encounter the highly abrasive Travis Peak and Cotton Valley formations at around 6,300 ft. The Travis Peak is normally reached at 6.300 - 6.500 ft, followed by the Cotton Valley from 8,000-8,300 ft to TD. The Travis Peak and Cotton Valley are each about 1,700-2,000 ft in length. Until recently, the extremely abrasive sections in these formations severely limited the life of the IADC Class 537 through 737 roller cone bits used to drill these wells. Between severe gauge and cutting structure wear, the bits run previously were normally pulled after about 600 ft of drilling. The shortened life meant six to 10 bits were required to complete the two intervals.

This paper describes the design and application of new hard formation rock bits that are drilling up to 50% more footage than the 627 and 737 types run previously. The new IADC Class 647 and 747 roller cone bits incorporate new insert geometries and quantities. along with improved carbide grades and diamond-enhanced gauge protection. Today, the Travis Peak and Cotton Valley are being drilled with four bits, averaging more than 850 ft per bit. Along with the new bits, a revised mud program consisting of low-solid polymers contributed to the improved performance realized in recent Panola County wells.

The authors will review the design process of the new bits. as well as presenting case studies of typical Travis Peak and Cotton Valley wells in Panola County and elsewhere in East Texas.

Introduction

The East Texas field was discovered in 1930 with the Joiner-Daisey oil well, Drilling had focused primarily on the shallower and highly productive oil bearing formations. While gas wells have been producing from the Travis Peak for more than 50 years, and gas sands were discovered in the Cotton Valley in 1937, it was not until 1968 that the first producing Cotton Valley gas well came on stream in Panola County. The Natural Gas Policy Act of 1978 and the Federal Energy Regulatory Commission's (FERC) tight gas sand policy of 1980 spawned interest in the gas reserves of the Travis Peak and Cotton Valley. Today, the focus of East Texas exploration is the marginal gas reserves. Fig. 1 outlines the East Texas area where most of the gas drilling takes place.

Stratagraphically, the lower Cretaceous Travis Peak comprises fine-grained to very fine-grained sandstones, muddy sandstones and sandy mudstones The sandstones are highly cemented and consist primarily of quartz with quartz cementation. Owing to the extremely cemented nature of Travis Peak sandstones, as confirmed in laboratory tests, the rock fails by fracturing the individual quartzitic sand particles, which accounts for the extremely abrasive nature of the formation.

P. 595
One Year Experience in Slim Hole Drilling
Authors: Sagot A. , Dupuis D.
Published: December 2007

Further to previous research and experimental wells drilled in 1993, in 3" and 3 3/8" ("Les Talonnieres", SPE Paper n•28299), and the decision to built the fitted for purpose Slim Hole rig FORASLIM 1 commissioned in April 1994 (SPE Paper n•28867, a Fitted for purpose Rig) 6 Slim Hole wells have been drilled for ELF AQUITAINE : 2 in the Paris Basin and 4 in (Gabon) West Africa.

Eighteen months of experience allow to make a global review of what are the achievements in terms of geological data acquisition, drilling performances, and economical results. This permitted to point out the weaknesses and the corresponding needed improvements to reach a mature Slim Hole technology fully comparable to the conventional approach.

The paper describes and analyses the operational results of each well as different prospects were drilled in respect of depth, geology. One significant experiment in a well drilled in 3 3/8" with high pressure at 3310 m (11 000'), requiring the use of mud weight of 1,75 sg (14,5 ppg) is in particular described.

Beside the review of drilling performances and geological data acquisition, an economical review will be made. A cost comparison with conventional approach provides an estimation of the benefits of the Slim Hole approach.

The potential use of a Slim Hole drilling offshore and for deep wells is finally presented.
Coiled Tubing Drilling Practices at Prudhoe Bay
Authors: Goodrich G. T. , Smith B. E. , Larson E. B.
Published: December 2007

Recent drilling experience has led to significant improvements in coiled tubing drilling (CTD) operations at Prudhoe Bay. Since implementation of a full time CTD program in mid 1994, over two dozen open-hole drilling operations have been performed in the Eastern Operating Area (EOA) of the Prudhoe Bay Field. Drilling programs have included simple extensions from pre-set liners to more complex through-tubing horizontal sidetracks. Horizontal sections greater than 1200 feet have been drilled. Measured depths in excess of 13,000 feet have been reached using two inch diameter coiled tubing with 3-3/4 inch bits. This paper will address current CTD techniques used at Prudhoe Bay and compare these techniques with rotary drilling methods.

Coiled tubing drilling techniques have evolved in response to drilling mechanics and hydraulics limitations of coiled tubing workstrings. Bottom hole assemblies (BHA) are designed to improve weight transfer. MWD directional package sensors are located as close to the bit as possible (11 to 12 feet) and directional changes are made incrementally to minimize dog leg severity. Less aggressive PDC style bits are used to reduce reactive torque and mud motor stalling. Drill rates of 10 to 20 feet per hour (fph) in shales and 30 to 70 fph in sands are typical. Bit wear is often negligible. Motor life or directional requirements typically limit a bit run.

Weight transfer, hole cleaning, and stuck pipe problems in high departure sections have been reduced through the use of low solids (less than one percent) polymer drilling mud. To improve hole cleaning and prevent cuttings bed build up, rates of penetration are controlled and short trips while circulating are performed frequently. Mud lubricants have improved weight transfer while drilling overbalanced.